Australian Renewable Energy Agency
08-Oct-2014
Australia's Off-Grid Clean
Energy Market Research
Paper
AECOM
Australia's Off-Grid Clean Energy Market Research Paper
Australian Renewable Energy Agency
Client: Australian Renewable Energy Agency
ABN: 35 931 927 899
Prepared by
AECOM Australia Pty Ltd
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08-Oct-2014
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08-Oct-2014
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AECOM
Table of Contents
Executive Summary
1.0
Introduction
2.0
Australia in the Global Context
2.1.1
Global renewable energy market
2.1.2
Australian energy industry
2.1.3
International remote or off-grid market
3.0
Australian Electricity Markets
3.1
Overview
3.2
National Electricity Market
3.3
South West Interconnected System (SWIS)
3.4
Australia’s fringe-of-grid market
3.5
Australia’s Off-grid Electricity Market
3.5.1
Overview
3.5.2
Existing off-grid generation
3.5.3
Value proposition for off-grid renewable energy
3.5.4
Australia’s off-grid renewable market size and distribution
3.5.5
Stakeholders consultations
4.0
Government Legislation, Policies and Programs
4.1
National energy policy in Australia
4.2
Australia’s Direct Action Plan
4.2.1
Emissions Reduction Fund
4.2.2
Solar Towns
4.3
Other major initiatives
4.3.1
The Renewable Energy Target (RET)
4.3.2
Australian Renewable Energy Agency (ARENA)
4.3.3
The Clean Energy Finance Corporation (CEFC)
4.3.4
ARENA’s Regional Australia Renewables (RAR) program
4.4
Other support programs
5.0
Off-grid Interconnected Systems
5.1
Western Australia
5.2
Northern Territory
5.3
Queensland
5.4
Renewable energy opportunities in off-grid interconnected systems
5.4.1
Large shopping centres and warehouses
5.4.2
Behind-the-meter installations on hospitals, schools, airports
5.5
Challenges to renewable energy in the off-grid interconnected systems
5.5.1
Economics
5.5.2
Opposing subsidies
5.5.3
Split incentives
5.6
Off-grid interconnected systems case studies
6.0
Off-grid Industrial Market
6.1
Mining sector
6.1.1
State of the market
6.1.2
Market outlook
6.1.3
Energy demand in the mining sector
6.2
Renewable energy in the mining sector considerations
6.3
Independent Power Producers
6.3.1
Energy Development Ltd
6.3.2
Pacific Energy
6.4
Off-grid industrial case studies
6.5
Other off-grid Industrial applications
6.5.1
Non-Mining Industrial renewable energy opportunities
7.0
Off-grid Communities Market
7.1
Western Australia
7.1.1
Remote communities
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9.0
Source: AECOM; (Horizon Power, 2012-13)
7.1.2
Key stakeholders
7.1.3
Renewable energy opportunities
7.1.4
Case Studies
7.2
Northern Territory
7.2.1
Territory growth towns and remote communities
7.2.2
Key stakeholders
7.2.3
Renewable energy opportunities
7.3
Queensland
7.3.1
Remote communities
7.3.2
Key stakeholders
7.3.3
Renewable Energy opportunities
7.3.4
Case studies
7.4
South Australia
7.4.1
Remote communities
7.4.2
Key stakeholders
7.4.3
Renewable energy opportunities
7.5
Independent remote networks
7.5.1
Islands
7.5.1
Outstations and homelands
7.5.2
Aboriginal communities in Western Australia, not serviced by Horizon Power
7.6
Summary of key opportunity areas
7.7
Challenges to renewable energy in the community market
Renewable Hybrid Considerations
8.1
Financial drivers
8.2
Feasibility assessment guide
8.2.1
Existing system assessment
8.2.2
Optimisation
8.3
Hybrid assessment tools
8.4
Enabling Technologies
8.4.1
Energy storage
8.4.2
Diesel generator performance
8.4.3
Cloud tracking
8.4.4
Demand management
8.4.5
Control systems
8.5
Common hybrid risks
8.6
Project procurement – contracting strategy options
Bibliography
Appendix A
Renewable Resources and Technology Status
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List of Tables
Table 1
Table 2
Table 3
Table 4
Table 5
Table 6
Table 7
Table 8
Table 9
Table 10
Table 11
Table 12
Table 13
Overview of the Global Remote Renewable Sub-segments
Summary of Australia's Energy Markets
Differences between NEM and SWIS (EnergyAction, 2012)
NEM Snapshot
SWIS Snapshot
Distribution of demand from the off-grid industrial and communities sectors
Capacity and percentage distribution of off-grid generation by region
Estimated off-grid renewable market size by Region (MW)**
Key observations from Off-grid renewable market
Key opportunities and recommendations for stakeholders
Remote energy programs
Electricity generation in 2011 in the NT regulated markets
Key stakeholders and challenges of large shopping centres and warehouses
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Table 14
Table 15
Table 16
Table 17
Table 18
Table 19
Table 20
Table 21
Table 22
Table 23
Table 24
Table 25
Table 26
Table 27
Table 28
Table 29
Table 30
Table 31
Table 32
Table 33
Table 34
Table 35
Table 36
Table 37
Table 38
Table 39
Table 40
Table 41
Table 42
Table 43
Table 44
CSO Subsidy Overview
34
Off-grid interconnected systems case studies
35
World ranking of Australia's mineral production and resources for 2009 (Source:
(Geoscience Australia, 2012), (Austrade, 2014))
36
Summary of Mining projects in the investment pipeline, October 2013
38
South Australian mines using off-grid diesel generation systems
43
Challenges and opportunities in the mining sector
44
EDL’s remote power stations
47
Case studies in the mining sector
48
Off-grid industrial opportunities
48
Key stakeholders and considerations of the Square Kilometre Array
49
Key stakeholders and considerations of Pilbara algae project
50
Approximate* Community Service Obligation payments to selected utilities for regulation
of remote electricity users
52
List of remote communities serviced by Horizon Power
54
Case studies in Western Australia
59
Territory Growth Town electricity supply status (2011)
62
Ergon Energy community asset portfolio ( December 2012)
64
Case studies of Ergon Energy remote communities
66
Diesel generation systems in South Australia
68
Case studies for integration of renewables on islands
69
NT remote communities renewable energy examples
70
Communities in the Shire of Ngaanyatjarraku
70
Challenges and solutions to renewable energy in the community market
72
Commonly used hybrid assessment tools
78
Overview of energy storage configurations with indicative performance factors
79
Diesel genset characteristics
80
Common hybrid risks
82
Contracting strategy options
84
Off-grid Renewables Technology & Resource Potential Overview
a-2
Long term generation potential of animal waste
a-6
Wave power pilot and demonstration projects in Australia
a-10
Proposed demonstration wave projects
a-11
List of Figures
Figure 1
Figure 2
Figure 3
Figure 4
Figure 5
Figure 6
Figure 7
Figure 8
Figure 9
Figure 10
Figure 11
Figure 12
Figure 13
Figure 14
Figure 15
Figure 16
Figure 17
Figure 18
Figure 19
Figure 20
Figure 21
Fringe-of-grid and off-grid areas of Australia
Composition of Residential electricity costs in 2012-13
National Electricity Market overview
Electricity production in the NEM by fuel type (FY 2012)
Map of SWIS
Proportion of generation in the SWIS by fuel type, 2011
NSP Average Network Customer Density
Off-grid generation in off-grid Australia
Distribution of Off-Grid Generation by State and Territory
Estimated off-grid renewable market size by Region (MW)
Non-renewable off-grid generation and hybrid potential in Australia
North West Interconnected System (NWIS)
Power Water Corporation interconnected systems and power stations
Energy intensive processes during the mining production chain
Committed mining investment for projects by Region
Advanced minerals and energy projects – October 2013
Primary energy consumption in the mining sector
Trends of intensity and yearly change in energy consumption in the mining sector
Average ore grades over time
Energy Developments Ltd power stations
Pacific Energy power generation facilities
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Figure 22
Figure 23
Figure 24
Figure 25
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Figure 41
Figure 42
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Remote and very remote populations in each State (as per the Australian Statistical
Geography Standard categories)
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The ten strongest growth mining cities
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Population change in WA between 2001 and 2011
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Electricity supply in Horizon Power remote communities (in GWh)
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Horizon Power’s power stations
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Population change in the Northern territory between 2001 and 2011
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Energy sources used by IES to supply electricity to Indigenous communities
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Population change in Queensland between 2001 and 2011
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Ergon Energy Network
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Population change in SA between 2001 and 2011
67
Solar PV cost comparison with diesel fuel-only costs (includes Fuel Tax Credit, excludes
large consumer buying power; assumes low penetration solar systems)
76
Break-point analysis of the cost of solar PV with diesel generation, as a function of PV
capital costs.
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Suitability of different energy storage technologies for grid-scale applications
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Projected LCOE for Power Generation Technologies in Australia by 2020 (NSW), with
carbon price set to zero.
a-1
Off-grid Gas and Diesel Power Generation
a-3
Wind Resource of Australia
a-5
Average Daily Solar Exposure (Annually)
a-8
Direct Normal Solar Irradiance
a-1
Tidal energy potential in Australia
a-3
Land use and bioenergy facilities in Australia
a-5
Australian operating hydroelectric facilities ( > 10 MW)
a-8
Spatial distribution of time-averaged wave power on the Australian continental shelf
(kW/m)
a-10
Potential for Geothermal in Australia
a-13
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AECOM
Executive Summary
This research paper was commissioned by the Australian Renewable Energy Agency (ARENA) to provide an
overview of the off-grid and fringe-of-grid renewable energy market in Australia to assist market entrants and
established participants obtain a broader appreciation of this emerging market. The paper provides an insight into
Australia’s renewable energy resources, electricity markets and regulatory environment through outlining current
industry perspectives on Australia’s off-grid and fringe-of-grid renewable energy market gleaned from published
papers and consultations with key stakeholders.
The paper will also serve as a baseline evaluation prior to the commitment of project funding through the
ARENA’s Regional Australia’s Renewable (RAR) Program and therefore focuses on the remote energy market up
to the end of 2013.
Overview of Australia’s electricity markets
Australia’s main energy markets comprise of the National Electricity Market (NEM) and South West
Interconnected Systems (SWIS). The NEM is the world’s longest interconnected power system with an end-to-end
distance of more than 4,000 kilometres and services over 9 million consumers across Queensland, New South
Wales, Tasmania, Victoria and South Australia. The SWIS services 2 million consumers and spans the area
surrounding Perth in southern Western Australia. The main source of electricity generation in the SWIS and NEM
is through centralised plant fuelled by coal and natural gas. Together these markets supply approximately 93 per
cent of all energy consumed in Australia. In 2013, renewable energy contributed approximately 15 per cent of the
overall electricity production.
The renewable energy market in Australia is growing rapidly, principally being driven by the Renewable Energy
Target (RET) scheme which currently supports growth towards 41,000 GWh of large-scale renewable energy by
2020 in addition to the 15,000 GWh of pre-existing hydroelectric generation. The RET also provides further
support for small-scale renewable energy projects.
Australia’s electricity markets overview
Electricity Markets
Capacity
Emissions
Consumption
GW
Share
TWh
Share
t CO2-e/MWh
NEM
49.0
83%
199
86%
0.93
SWIS (WA)
5.5
9%
17.7
8%
0.82
Off-grid Mining Market
3.9
6%
12.4*
5%
Off-grid Community Market
1.0
2%
3.4*
1%
0.61
Source: AECOM, AEMO, IMO, Department of Climate Change and BREE
* Excludes NSW, ACT, VIC and external territories of Australia for confidentiality reasons
Off-grid electricity market overview
For the purposes of this paper, Australia’s off-grid electricity market is defined as a combination of fringe-of-grid
areas in remote locations and off-grid areas, defined as:
-
Fringe-of-grid encompasses areas in the NEM and SWIS that are remote and have a relatively high
likelihood of supply reliability or power quality issues.
-
Off-grid comprises of isolated or islanded electricity systems that are not connected to the NEM or SWIS.
-
Remote areas are defined as areas classified as ‘Remote Australia’ or ‘Very Remote Australia’ in the
Australian Statistical Geography Standard (ASGS): Volume 5 - Remoteness Structure, July 2011 (ABS cat.
No. 1270.0.55.005)
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AECOM
Fringe-of-grid and off-grid areas
Source: AECOM, ABS
This paper largely focuses on off-grid areas,
however, it is acknowledged that there is an
extensive fringe-of-grid market which services
remote parts of Australia. The adjacent figure
geographically illustrates the fringe-of-grid and
off-grid areas.
Only 2 per cent of Australia’s population live in
off-grid areas, however over 6 per cent of the
country’s total electricity is consumed in off-grid
areas. Around 74 per cent of that electricity is
generated from natural gas and the remainder
is mostly from diesel fuel; making it Australia’s
most expensive electricity due to the underlying
high gas and diesel prices in the remote areas.
However, due to lower levels of coal
generation, the off-grid market has the lowest
average emission intensity of all of Australia’s
electricity markets despite only 1 per cent of
electricity is generated from renewable
sources. An estimated 15,575 GWh of
electricity was produced in 2012 by off-grid
generation in Australia; supplied from a total
installed off-grid generation capacity of
approximately 5GW.
Much of the off-grid electricity market has experienced an increase in demand in recent years associated largely
with expansion in the mining industry. In general, the off-grid electricity market has also experienced an increasing
interest in renewable energy as a potential means to reduce the costs of electricity.
Remote clean energy support
Existing off-grid generation
The Australian renewable energy sector
attracted $5.2 billion of investment in 2013 and
there is now considerable industry interest in
the remote clean energy market. The Clean
Energy Council has estimated that 14.8
per cent of Australia’s electricity generation
was produced by renewable sources in 2013.
Practical experience and case studies will likely
facilitate further uptake of renewables,
particularly in off-grid industrial and mining
applications. ARENA’s mandate to disseminate
the knowledge generated from the projects it
supports will be essential to progress the
industry’s understanding of the lessons learnt
and develop the confidence of end users and
remote grid operators in the technology’s
value.
ARENA’s RAR Program intends to fund up to
$400 million to support investment of
renewables in off-grid and fringe-of-grid clean
energy projects by 2018. The funding focuses
on two market segments:
Source: AECOM
Regional communities that are not
connected to NEM or SWIS (through the
Community and Regional Renewable Energy
(CARRE) program); and
-
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The industrial and mining sector, (through
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AECOM
the industrial program, “I-RAR”), which seeks to support projects greater than 1MW.
ARENA’s RAR Program will be complemented by other programs and schemes such as the Clean Energy
Finance Corporation (CEFC), the Renewable Energy Target (RET) and state based funding towards renewable
energy.
Estimated market size
In estimating the off-grid market size, AECOM has considered both high and low penetration potential. The
establishment of ARENA’s RAR and other Government support programs were also taken into consideration in
addition to future renewable technology development which will enable greater uptake.
In the short to medium term, it is forecasted that hybridising renewables will begin at a low penetration in Western
Australia, the Northern Territory and Queensland with up to a possible 150 - 200 MW (corresponding to
approximately AUD $450 - $600 million in capital value) of project opportunities available. As confidence and
demand for more remote energy grows, and technology costs fall and develop over time, there may be potential
for higher penetrations of renewables. This could unlock an additional 850 MW or a total of over 1 GW of off-grid
renewables at a capital value of over AUD $2 billion.
Estimated market size of off-grid renewables
Source: AECOM
The business case
Renewables as a future fuel security and price off-set option has now become a more attractive proposition in offgrid Australia. The modular nature of many renewable technologies (such as wind and solar photovoltaics) and
the recent expansion of these industries with associated reductions in cost, means that new opportunities are
emerging for developing off-grid clean electricity supplies. Currently there is over 1.2GW of diesel generation
capacity installed in off-grid Australia which supplies electricity to mines and communities at a cost of $240450/MWh in fuel only (excluding capital costs). These costs are expected to rise over time and are vulnerable to
price shock events or supply chain interruptions in international markets.
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AECOM
Solar PV cost comparison with diesel fuel-only costs
(includes Fuel Tax Credit; assumes low penetration solar systems)
Source: AECOM
The off-grid renewable electricity market is relatively undeveloped in Australia, with a number of challenges
needing to be overcome before mass deployment can be occur. Other than some unique project opportunities,
the market is currently focused on adapting mature renewable technologies into existing off-grid power stations to
offset operating fuel costs. Each project will likely be evaluated on a levelised cost of electricity (LCOE) basis, with
a consideration of system reliability and integration issues associated with constructing and maintaining plant in
an isolated location. Traditional fossil fuelled generation is well understood, conversely there remains a lack of
experience of integrating renewables into off-grid Australia at scale. Therefore some stakeholders initially may find
it difficult to appreciate the value proposition.
The remoteness of these projects is a key factor for consideration, not only for construction, but also for long term
operations and maintenance. The need for training of regional maintenance resources will need consideration as
the market develops in addition to aggregating smaller projects within remote regions to increase construction,
operational and maintenance economies of scale. Also, much of off-grid Australia is susceptible to extreme
climatic events which could impact plant longevity and design considerations, and hence viability.
Despite these challenges, many developers, off-grid interconnected system operators and end users are planning
to incorporate renewable energy into off-grid applications. In the short term, the focus is likely to be on hybridising
wind turbines and solar photovoltaics with existing generation facilities. The reduction in some renewable
technology costs and availability of government support programs has made renewables as a future fuel security
and price off-set option a more attractive proposition.
In the absence of government support programs, the longer term sustainability of the off-grid renewable market
will largely be dependent on fossil fuel prices, the development of enabling technologies (such as batteries, low
load diesel engines and ‘smart’ control systems) and market confidence in available renewable technologies.
Furthermore, the finance sector’s appetite to support the projects will be critical to future success. The finance
sector will be influenced by the risk associated with any technology or project, the size of investment and the
policy certainty.
There already is an emerging business case for fuel off-setting through hybridising mature renewable
technologies with existing off-grid diesel generation systems at low penetrations. In locations with high diesel
prices, the levelised cost of hybridisation of a diesel system with wind or solar is already comparable with the cost
of diesel that would be offset by such a system. In the medium to longer term, gas price increases are expected in
Australia’s eastern gas markets as local producers begin to service the demands of local Asian markets through
export LNG. This will further enhance the viability of integrating renewables with gas-fuelled generators,
particularly as further technology cost reductions are expected and energy storage technologies evolve.
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Conclusion
The largely untapped off-grid clean energy market and funding support available from the Australian Government,
creates an attractive opportunity for the Community and Industrial off-grid sectors to pursue cheaper and cleaner
electricity supply. The market segments with the largest opportunities include:
-
renewable hybridised generation systems represent the greatest potential area for investment, particularly
when associated with existing diesel-fired power plants
-
industrial/mining growth regions of Western Australia, Queensland and the Northern Territory
-
community growth regions where aggregation of smaller projects particularly in growing mining towns such
as Roxby Downs (SA), Weipa (QLD), in addition to Karratha, Newman and the greater Pilbara in Western
Australia which have shown significant electricity demand growth as a result of fly-in-fly-out and permanent
population expansion in recent years
-
off-grid interconnected systems such as the North West Interconnected Systems (NWIS) in Western
Australia operated by Horizon Energy, Darwin - Katherine System in the Northern Territory operated by
Power and Water Corporation and, Mount Isa Grid in Queensland operated by Ergon Energy.
In realising these opportunities it is recognised that deployment of cost effective enabling technologies,
development of system integration expertise and remote training programs will be essential to accelerate uptake,
ensure reliability and sustain the confidence of end-users.
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AECOM
Glossary
Term
Meaning
Term
Meaning
ACRE
Australian Centre for Renewable Energy
IPP
Independent Power Producer
AEMC
Australian Energy Market Commission
LCOE
Levelised Cost of Energy
AEMO
Australian Energy Market Operator
LGC
Large Scale Generating Certificates
AER
Australian Energy Regulator
LNG
Liquefied natural gas
ARENA
Australian Renewable Energy Agency
LRET
Large-scale Renewable Energy Target
AUD
Australian Dollar
MJ
Megajoule
BOO
Build Own Operate
MW
Megawatt
BREE
Bureau of Resources and Energy
Economics
MWh
Megawatt hour
CARRE
Community and Regional Renewable
Energy program
NEM
National Electricity Market
CEFC
Clean Energy Finance Corporation
NSP
Network Service Provider
CNG
Compressed Natural Gas
NWIS
North West Interconnected System
CO2-e
Carbon dioxide equivalent
PJ
Petajoule
COAG
Council of Australian Governments
PPA
Power Purchase Agreement
CSIRO
Commonwealth Scientific and Industrial
Research Organisation
PV
Photovoltaic
CSO
Community Service Obligation
PWC
Power and Water Corporation
DNSP
Distribution Network Service Provider
RAR
Regional Australia Renewables (an
ARENA program)
EPC
Engineer, Procure, Construct
RET
Renewable Energy Target
EPCM
Engineer, Procure, Construction
Management
SRES
Small Renewable Energy Scheme
GJ
Gigajoule
SRMC
Short-run Marginal Cost
GST
Goods and Services Tax
STC
Small-scale Technology Certificate
GW
Gigawatt
TJ
Terajoule
GWh
Gigawatt hour
TNSP
Transmission Network Service Provider
IEA
International Energy Agency
UPS
Uninterruptible Power Supply
IES
Indigenous Essential Services
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Preamble
This research paper was commissioned by the Australian Renewable Energy Agency (ARENA) to provide an
overview of the off-grid and fringe-of-grid renewable energy market in Australia to assist market entrants and
established participants obtain a broader appreciation of this emerging market. The paper provides an insight into
Australia’s renewable energy resources, electricity markets and regulatory environment through outlining a
summary of current industry perspectives on Australia’s off-grid and fringe-of-grid renewable market from
published papers and consultations with key stakeholders.
The paper also provides a baseline evaluation prior to project funding being committed through the ARENA’s
Regional Australia’s Renewable (RAR) Program and therefore focuses on the remote energy market up to the
end of 2013.
RAR Program Objectives:
-
To demonstrate a portfolio of renewable energy solutions, including hybrid and integrated systems, in
Australian off-grid and fringe-of-grid areas;
-
To ensure knowledge is produced and disseminated regarding the deployment of renewable energy
solutions in remote areas catalysing further renewable energy uptake;
-
To remove roadblocks, leading to greater deployment of renewable energy solutions in off-grid and fringe-ofgrid areas.
RAR Program Expected Outcomes:
-
Within five years, result in at least 150MW of renewable energy projects in off-grid and fringe-of-grid
locations where fossil fuels are currently or would otherwise be used. This would include two or more ≥
10MW projects;
-
The renewable energy capacity is appropriately utilised for at least five years following commissioning;
-
Key roadblocks to the greater implementation of renewable energy are removed, including, but not limited to
integration and control system risk, and low reliability perceptions;
-
Regional communities and industry gain more skills in operating and maintaining renewable energy
solutions;
-
Knowledge produced and disseminated regarding the economic viability of renewable energy solutions in
remote areas catalyses further commercially based renewable energy deployment.
The ARENA’s RAR Program has already attracted considerable market interest and the assistance pledged will
likely increase the broader acceptance of renewable energy in remote regions. Practical experience and case
studies deployed by this program will likely facilitate further uptake of renewables particularly in the off-grid
industrial and mining sectors. Dissemination of the learnings from these projects will be essential to progress the
industry’s understanding of the lessons learnt and develop the confidence of end users and off-grid
interconnected system operators in the technology.
Further information about the RAR program is detailed in section 4.3.4.
We would like to acknowledge the support we have received during the development of this research from:
-
Australian Renewable Energy Agency (ARENA)
-
Clean Energy Finance Corporation (CEFC)
-
Department of Resources, Energy and Tourism (now the Department of Industry)
-
Australian Government Clean Energy Working Group, represented by State and Territory Governments and;
-
Australian industry contacts including ATCO Australia, Atlas Iron, Charles Darwin University, Commonwealth
Bank of Australia, Eltek, HST, IT Power, Pilbara Development Commission, Power Water Corporation, Rio
Tinto, SA Department of Manufacturing, Innovation, Trade, Resources and Energy, SMA, Solco, Western
Desert, Australian Trade Commission (Austrade), Xtreme Power and ZBB.
Initial research work for this study was funded by Austrade in 2012-13 with the purpose of providing foreign
investors and developers with a greater understanding of Australia’s energy market, in particular outlining the off-
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grid energy market opportunities in Australia. Please contact AECOM or ARENA if you have further queries. We
look forward to the expansion of the off-grid and fringe-of-grid renewable energy market in Australia.
Contact Details
AECOM
Craig Chambers, Market Sector Director – Power
Direct: +61 2 8934 1060
Craig.Chambers@aecom.com
ARENA
Steve Rodgers
Gabriele Sartori
Disclaimer
AECOM acknowledges that the datasets used to define the market size may have anomalies and therefore are
not complete. As such, some figures presented in the paper are subject to significant uncertainty. All stakeholders
should use their own discretion before making any financial investments or decisions based on the information
contained in this paper. AECOM does not accept any liability for any decisions made on the basis of this
information. AECOM were initially engaged by Austrade to undertake a broad study of Australia’s electricity
industry to gain detailed insight into how the current policy and market is impacting off-grid renewable investment.
Subsequently, ARENA has engaged AECOM to update the paper and provide a summary of current industry
perspectives on Australia’s off-grid renewable market.
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1.0
Introduction
This paper is intended to identify the characteristics of the off-grid and fringe-of-grid renewable energy markets, to
highlight key stakeholders and identify project opportunities. The research contained draws upon publicly
available literature, various consultations held with stakeholders both in industry and Government and AECOM’s
market knowledge to articulate the value proposition of the off-grid renewable marketplace in Australia.
This paper has aligned its definition of the off-grid renewable market with the Australian Renewable Energy
Agency’s Regional Australia’s Renewables Program (ARENA’s RAR Program), which is;
a)
Fringe-of-grid: Areas in the National Electricity Market or the South West Interconnected System that are
remote, with a relatively high likelihood of supply reliability and power quality issues being experienced.
b)
Off-grid: Isolated or islanded systems (including private systems) or grids that are not connected to the
National Electricity Market or the South West Interconnected System.
c)
Remote: Areas defined as ‘Remote Australia’ or ‘Very Remote Australia’ in the Australian Statistical
Geography Standard (ASGS): Volume 5 - Remoteness Structure, July 2011 (ABS cat. No. 1270.0.55.005)
This paper primarily focuses on off-grid areas, although it is acknowledged that there is an extensive fringe-of-grid
market servicing remote parts of Australia for which much of the enclosed report is also relevant. The figure below
geographically illustrates the fringe-of-grid and off-grid areas.
Figure 1
Fringe-of-grid and off-grid areas of Australia
Source: AECOM, ABS
The paper has been prepared to provide;
a)
an overview of Australia’s energy market in the global context, and the market for renewables in Australia;
b)
an introduction to the off-grid market, providing context for those unfamiliar with Australia’s energy markets;
c)
an overview of Australian legislation relevant to the clean energy industry in an off-grid context; and
d)
an overview of the commercial and technical considerations for remote renewable projects.
e)
an overview of Australia’s renewable resource and corresponding technology status.
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2
Furthermore to align with the market sectors as defined by ARENA’s RAR Program, this paper is structured
around two main market sectors that are currently expanding or are demonstrating potential for imminent growth,
namely:
Off-grid Industrial Sector: The industrial and commercial regional energy market, dominated by the off-grid
mining segment and including defence, agricultural and tourist facilities with renewable energy opportunities
greater than 1 MW including those connected to off-grid interconnected systems. (section 6.0)
-
Off-grid Community Sector: The community market, which includes small and very small off-grid
communities, fast growing mining towns, islands, small commercial facilities with renewable energy
opportunities between 100kW and 1MW, including those connected to off-grid interconnected systems.
(section 7.0)
Off-grid interconnected systems – Darwin-Katherine, Alice Spring, North West Interconnected System (NWIS) and
Mount Isa span across both these market segments and are discussed in section 5.0.
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2.0
Australia in the Global Context
2.1.1
Global renewable energy market
Investment in electricity generation around the world is increasingly moving towards renewables. Although
investment in renewable energy fell in 2013 for the second year in a row (totalling US$2214 billion and 23 per cent
below the 2011 record), non-hydro renewable generation accounted for 44 per cent of new generation capacity
installed globally. The small investment drop in the last two years compared to previous years was reported to be
driven by the falling cost of solar photovoltaic systems as well as policy uncertainty in many countries.
Developing economies made up 35 per cent of this total investment, compared to 65 per cent for developed
economies and for the first time in 2013, China invested more in renewable energy than Europe. Hydropower and
solar photovoltaic (PV) each accounted for approximately one third of new renewable capacity in 2013, followed
by wind which contributed nearly 30 per cent (REN21, 2014). This was the first time that installed solar capacity
was greater than wind. By the end of 2011, renewables comprised more than 26.4 per cent of total global powergenerating capacity and supplied an estimated 22 per cent of global electricity. Non-hydropower renewables
exceeded 560 GW, a 17 per cent capacity increase over 2012 (REN21, 2014). Modelling by the International
Energy Agency (IEA) projects that renewable technologies could form half of all new additional capacity worldwide
through to 2035 (IEA, 2012)
There are many drivers for this rapid market shift towards renewable technologies, including falling renewable
energy costs, energy security, carbon reduction policies, rising fossil fuel costs and avoidance of the externalities
associated with fossil fuel generation. At least 118 countries, more than half of which are developing countries,
had renewable energy targets in place by early 2012, up from 109 as of early 2010. Renewable energy targets
and support policies continue to be a driving force behind renewable energy markets, despite some setbacks
resulting from a lack of long-term policy certainty and economic stability in many countries. Since the global
financial crisis, and particularly over the last two years, several countries have undertaken significant policy
overhauls primarily as a result of austerity measures that have resulted in reduced support for renewable energy.
Nevertheless, policymakers are increasingly aware of renewable energy’s wide range of benefits—including
energy security, reduced import dependency, reduction of greenhouse gas emissions, prevention of biodiversity
loss, improved health, job creation, rural development, and energy access.
For the majority of remote electricity users globally, off-grid renewable electricity is less expensive than extending
the power grid. Renewable energy projects in developing countries have contributed to energy poverty alleviation
by providing education, reducing hunger, disease through the access to safe drinking water and the creation of
jobs supporting the increase in living standards.
Ernst & Young have developed a Renewable Energy Country Attractiveness Index (RECAI) score for 40
countries, which ranks countries based on the attractiveness of their renewable energy markets, energy
infrastructure and the suitability for individual technologies. The top five countries were (in order) the USA, China,
Germany, Japan and the UK. Australia was ranked 8th. (Ernst and Young, 2014)
2.1.2
Australian energy industry
2.1.2.1
Energy Mix
Australia is a stable and prosperous developed nation. Unlike many other developed nations, Australia has
historically demonstrated consistent electrical demand growth underpinned by a strong and rapidly expanding
primary resources industry. In recent years, demand growth has declined in the National Electricity Market (NEM).
Due to significant uncertainty around the impacts of declining manufacturing, energy efficiency measures and
continued growth in rooftop solar photovoltaics on future projections, the Australian Energy Market Operator
(AEMO) has continuously revised the projected long term demand growth to a slower rate.
Australia has substantial domestic coal resources, which form the basis of a large coal export industry with coal
exports anticipated to double by 2020 (BREE, Australian Energy Projections to 2034-35, 2011), and continue to
grow through to 2030. Furthermore, the mega LNG projects in development around Gladstone and the
development of coal seam gas resources on the east coast of Australia could see Australia overtaking Qatar to
become the largest LNG exporter in the world by 2020 (Winning, 2012).
The abundance of coal resources in Australia has led to approximately 75 per cent of Australia’s electricity being
generated from coal-fired generation. This, combined with economic and political stability, has made Australian
electricity cheap, reliable and low risk. Thus, Australia has been a home of energy intensive industry, such as
aluminium refineries and smelters for many years.
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However, high reliance upon coal-fired generation means that electricity production is highly carbon intensive in
Australia. With global pressure to reduce greenhouse gas emissions, Australia’s electricity sector will need to
progress towards lower emissions generation in order to maintain its competitiveness. With the expansion of LNG
exports out of Australia and expansion of shale gas in the United States, the energy production mix in Australia
will be dictated by dynamics in international commodity markets, determining the availability and price of
traditional fossil fuels in domestic markets. If international LNG prices fluctuate upwards, future energy production
investments will likely continue to be a mixture of fossil fuel and renewable energy. However, if LNG prices
fluctuate downward, some are predicting a global trend toward gas as the primary energy fuel source. Global LNG
prices could have a significant impact on Australia’s coal and LNG exports and likely influence the uptake of
renewables.
In addition to its coal and gas resources, Australia has vast renewable resources. World class wind resources are
generally prevalent in the southern parts of the nation, combined with large sunny arid regions mean that Australia
is well placed for competitive investment in renewables.
Australia is currently experiencing an unprecedented decline in demand for electricity across the National
Electricity Market (NEM), and a flattening of demand in the South West Interconnected System. AEMO has stated
that no new capacity is required in any NEM region to maintain supply-adequacy over the next 10 years (AEMO,
2014). Therefore it is expected that investment in new generation will be dominated by renewable sources.
2.1.2.2
Electricity Prices
In Australia, the price of electricity is determined by a number of factors such as transmission and distribution
network costs, the wholesale electricity price faced by retailers, and government policies. Recently, a major driver
of rising retail electricity prices has been the significant investment in new, and the upgrading of existing,
transmission and distribution infrastructure required to support increasing (peak rather than overall) demand for
electricity.
The Australian Energy Regulator estimates that transmission and distribution network costs will represent 36-57
per cent of the retail electricity price faced by NEM-connected households in 2012–13, with wholesale electricity
prices representing on average a further 21 to 27 per cent (Figure 2). The disperse nature of Australia’s energy
infrastructure that seeks to support its relatively small population over vast distances, motivates the focus toward
supporting off-grid energy demand with the use of renewables.
Figure 2
Composition of Residential electricity costs in 2012-13
*Environmental component includes green schemes and the carbon tax (which has since been repealed)
Source: (AEMC, 2013)
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2.1.3
International remote or off-grid market
Over 1.2 billion people approximately 20 per cent of the world's population currently live without access to
electricity worldwide, almost all of whom live in developing countries. This includes 550 million in Africa and over
400 million in India. About 2.8 billion people use solid fuels (wood, charcoal, coal and dung) for cooking and
heating (World Bank, Energy).
Without energy, many developing economies cannot grow and poverty cannot be reduced. Energy is an important
input to all sectors of the economy, fuelling transport to move goods and people and providing electricity to
industry, commerce, agriculture, and important social services such as education and health. Access to electricity
is a global challenge, particularly in remote areas which historically have pursued cheaper solutions over more
environmentally and socially sustainable options.
Due to the modular nature of many renewable technologies (such as wind and solar photovoltaics) and the recent
expansion of these industries with associated reductions in cost, new opportunities for development of off-grid
electricity supply are emerging. The international growth markets for renewable generation in remote locations are
being experienced in both developed and developing countries such as Arctic Canada, Brazil, Asia and many
African countries. Rapidly developing nations such as India and China also have substantial populations in remote
areas; in India, around a third of the population relies on off-grid generation systems with further growth expected
in this sector due to the instability of the electricity grid. It is recognised that the remote hybrid market is a
precursor to the likely uptake of hybrid and renewable enabling technologies in a grid connected application.
Internationally there are four main sub-segments to the remote renewable sector as outlined in table 1 below.
Table 1
Overview of the Global Remote Renewable Sub-segments
Remote
Renewable
Sub-Segment
Typical
Size
Range
Remote
Community
Systems
<2MW
Isolated
Interconnected
Systems
<5MW
Overview
Examples in Australia
Perhaps the largest number of remote
renewable installations today would fall
into this category, though data is
extremely scarce due to the small scale
of such projects and large number of
installations. An average community
renewable power system has a
capacity of 100 kW and is used to
displace diesel or other fuel sources.
They typically provide power to remote
villages, islands, tourist facilities,
industrial and military installations,
houses, clinics, schools, and stores or
an individual dwelling. Although the
smallest in scale, the investment
required for community power systems
per kilowatt is large in comparison with
any other sub-segment.
Bushlight is part of the Centre for
Appropriate Technology (CAT), an
Australian non-profit organisation which
works with Indigenous communities
throughout regional and off-grid
Australia. CAT offers customised
renewable systems for rugged, remote
applications.
Weak islanded grids represent another
opportunity for renewables. The lack of
options for power and fuel supply to
support these remote grids makes
renewable energy an attractive option
for network support and peak demand
management particularly when installed
using energy storage technologies such
as batteries.
Powercorp, which was acquired by
German transmission and distribution
multinational ABB in 2011, adopted its
patented flywheel PowerStore system
for peak lopping, frequency regulation
and integration of intermittent
renewable technologies into hybrid
applications such as Horizon Power’s
Marble Bar solar installation in Western
Australia.
Typical applications include water
pumping, disinfection, desalination,
communication stations, navigational
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Using this concept and through funding
from AusAid, CAT developed and took
its technology to India in 2009/10 to
support a remote community with
renewable energy using its
understanding from remote Australian
installations.
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Remote
Renewable
Sub-Segment
Typical
Size
Range
Overview
Examples in Australia
aids and road signals.
Industrial
Remote Mining
Mobile Military
or Disaster
Recovery
<30MW
<10MW
This sub-segment of the remote
renewable market is the least mature,
but has a high growth potential due to
an improving business case as well as
increased interest in shifting to more
sustainable energy strategies for sites
controlled by large multinationals.
Currently, few overseas remote mining
operations are deploying renewable
energy generation.
Galaxy Resources’ Mt Cattlin lithium
mine currently uses renewable energy
sources for up to 15 per cent of its total
power, using solar tracking panels
developed by Swan Energy.
This last category of remote
renewables is the least developed, but
has the most policy and financial
support particularly from the U.S.
Department of Defence. At present,
renewable systems are being deployed
in pilot projects in Afghanistan and
other remote Defence locations.
According to the Australian Defence
Force White paper on the Cost of
Energy (2013), Defence transport must
be converted to run on electricity on
solar photovoltaics and wind power to
remain viable.
The requirement to protect or extend
fuel use which renewables can provide,
is highlighted by the direct relationship
between fuel transportation and
casualties (Army Technology, 2010)
during war.
Similar drivers to the defence are the
humanitarian services operations where
power is often intermittent in regions
where disasters have occurred and
renewables can provide both a short
and long term benefit to the community
or region recovering from any
catastrophic event.
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The mining company intends to also
install three wind turbines, each with a
1.2 megawatt capacity, as well as a
solar power system with a one
megawatt capacity to power the site.
Australia’s Defence Science and
Technology Organisation (DSTO), in
collaboration with the Commonwealth
Scientific and Industrial Research
Organisation (CSIRO) have taken
significant strides towards developing a
self-powered generating device to
assist soldiers in the field.
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3.0
Australian Electricity Markets
3.1
Overview
There are a number of independent electricity grids in Australia, with no electrical interconnection between them:
-
National Electricity Market (NEM) - The NEM is the largest grid in Australia, spanning the eastern and
southern states, providing a fully interconnected network from northern Queensland through New South
Wales, the Australian Capital Territory, Victoria, South Australia and Tasmania. The NEM features a
sophisticated market operated by the Australian Energy Market Operator (AEMO) that supplies around 86
per cent of the electricity demanded in Australia as shown in Table 2.
-
South West Interconnected System (SWIS) – The SWIS grid spans the area around Perth in southern
Western Australia. The Independent Market Operator of Western Australia (IMO WA) operates the
Wholesale Electricity Market (WEM) in the SWIS, supplying approximately 8 per cent of the electrical
demand in Australia. The SWIS is not electrically connected to the NEM due to the very large physical
distance between these grids and the sparseness of the population in the land in between.
-
Other isolated interconnected systems – In addition to the NEM and the SWIS, there are multiple
independent interconnected systems in locations such as the Pilbara, the Northern Territory and Mt Isa.
These isolated interconnected systems are operated by local network providers or local industries (such as
the mining operations that they supply) and do not feature sophisticated market structures. Supply in these
systems is still considered ‘off-grid’ by definition. These isolated interconnected systems are presented in
section 3.6.
Table 2
Summary of Australia's Energy Markets
Energy Markets
Capacity
Consumption
Emissions
GW
Share
TWh
Share
t CO2-e/MWh
NEM
49.0
83%
199
86%
0.93
SWIS (WA)
5.5
9%
17.7
8%
0.82
Off-grid Mining Energy Market
3.9
6%
12.4*
5%
Off-grid Community Energy Market
1.0
2%
3.4*
1%
0.61
Source: AECOM, AEMO, IMO, Department of Climate Change and BREE
* Excludes NSW, ACT, VIC and external territories of Australia for confidentiality reasons
The establishment of sophisticated markets supplying the majority of electrical load in Australia (via the NEM and
the SWIS) has been part of a larger transformation of the Australian energy industry over the last two decades.
This has included the removal of regulatory challenges to interstate trade and the disaggregation of public
monopolies into separate entities for generation, transmission, distribution and retail. Following disaggregation,
competition was introduced into the generation and retail markets. Most of the eastern states have privatised
some or all of their electricity supply. The gas industry has undergone similar restructuring allowing competitive
energy markets.
The following table provides an overview of the differences between the NEM and SWIS, the two main electricity
networks in Australia.
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Table 3
Differences between NEM and SWIS (EnergyAction, 2012)
NEM
SWIS
Coverage Area
NSW, VIC, QLD, SA, ACT, TAS
South West region of WA
Energy Generated
211,000 GWh
17,500 GWh
Number of Generators
306 Generators
46 Generators (biggest being Verve
Energy (now Synergy))
Number of Retailers
26 Retailers
11 Retailers
(Three major – AGL, Origin Energy,
EnergyAustralia)
(Three major – Synergy, Alinta, Perth
Energy)
Coverage
800,000 km of power lines
90,000 km of power lines
Network Areas
13 Distribution Networks
South West Interconnected Network
Metering
Contestable Market
Monopoly – Western Power
Wholesale Market
Operator
Australian Energy Market Operator
Independent Market Operator (IMO WA)
Regulatory
Australian Energy Regulatory
Economic Regulation Authority (ERA WA)
Contestability
Full Retail Contestability (except <50MWh
TAS)
Retail contestability only available for
consumers >50 kWh per annum
Wholesale Market
AEMO Spot Pool Market
STEM and Reserved Capacity Market
Market System
Pool based energy market (Gross pool
market
Pool based with capacity and energy
traded separately
Spot Market Price Cap
$12.500 / MWh
$300/MWh for gas-fired
Overview
Network Details
Regulatory Details
Market Details
$700/MWh for liquid fired
Long Term Financial
Settlements
Future or over-the-counter contracts
(AFMA and Futures published on SFE)
Bilateral Contracts (Settled by IMO and
Short Term Financial
Settlements
AEMO Spot Pool Price
Short Term Energy Market (STEM)
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3.2
National Electricity Market
The National Electricity Market (NEM) is the wholesale market for the supply of electricity in Queensland, New
South Wales, the Australian Capital Territory, Victoria, South Australia and Tasmania. An overview of NEM
characteristics is provided in Table 4.
Table 4
NEM Snapshot
Category
Characteristics
Demand
Winter peak demand 2012-13 of 30.5GW (the maximum historical winter demand of
34.4GW occurred in 2008)
Summer peak demand 2012-13 of 32.5GW (the maximum historical summer demand of
35.6GW occurred in 2009)
Annual electricity consumption of 199TWh (2012-2013)
9.3 million customers
Supply
Installed generation capacity of 48.2GW (2012-13)
317 registered Generators
Networks
13 major distribution networks
Greenhouse emissions
319 million tonnes of CO2-e in 2013 (electricity generation in the NEM)
Emissions intensity of electricity generation in the NEM was 0.875 tonnes of carbon
emissions per MWh in 2012-2013.
Electricity generation is responsible for approximately 35% of Australia’s greenhouse
gas emissions.
Connection Rules
National Electricity Rules (NER) - Available on the Australian Energy Market
Commission (AEMC) website:
http://www.aemc.gov.au/Electricity/National-Electricity-Rules/Current-Rules.html
Source: AEMO; ESAA, State of the Energy Market 2013, AER, (Department of Energy, 2014)
The NEM operates on the world’s longest interconnected power system from Port Douglas in Queensland to Port
Lincoln in South Australia – a distance of more than 4,000 kilometres. The total length of distribution infrastructure
in the NEM is around 760 000 kilometres—17 times longer than transmission infrastructure. More than AUD $11
billion of electricity is traded annually in the NEM to meet the demand.
The NEM has been operating since December 1998, with the link to Tasmania established in 2006. Operations
today are based on six interconnected regions that largely follow state boundaries. Market operation is governed
by the National Electricity Rules (NER) and is managed by the Australian Electricity Market Operator (AEMO).
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Figure 3
National Electricity Market overview
Source: (AER, 2013)
The NEM operates a competitive spot market in which prices adjust in real time to supply and demand conditions
through an interconnected synchronous electricity transmission network. Exchanges between electricity producers
and electricity consumers are facilitated through an electricity pool where the output from all generators is
aggregated and scheduled to meet demand (AEMO, 2010).
The below figure illustrates the generation by fuel type within the NEM which is largely dominated by coal fired
generation.
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Figure 4
Electricity production in the NEM by fuel type (FY 2012)
Source: (AEMO, 2012)
Despite earlier projections of continuing growth, demand in the NEM has flattened since 2007-08 and declined in
recent years (AER, 2013). Future projections continue to anticipate growth albeit slower growth as there remains
significant uncertainty around the impacts of declining manufacturing, energy efficiency measures and the
continued growth in rooftop solar photovoltaics. This, combined with the uncertainty around national and
international carbon actions, means no additional coal-fired plant is expected to be built in the NEM in the coming
future. The shift away from investment in coal-fired plants has been occurring over the last 10 years, with the
majority of new investments being in gas fired generation and renewables.
Future electricity generation investment in the NEM is likely to be primarily driven by the Renewable Energy
Target (RET), with approximately $18 billion expected to be invested in wind between 2011 and 2018 and $16
billion in solar photovoltaics (PV) (AER, 2013). Further investment in gas-fired technologies is also anticipated,
largely in plant intended to assume a ‘peaking’ role in the market. Growth in bulk generation from gas is likely to
be hampered by challenges in obtaining long term contracts for gas supply, due to competition with the emerging
LNG export markets.
The connections process in the NEM is outlined in Chapters 5 and 5A of the NER. These processes are applied
somewhat differently by each Network Service Providers in each region, which can create challenges for project
developers. Attempts to streamline and improve this process are underway but it remains an area where
assistance from local specialists is likely to be of significant benefit to developers.
3.3
South West Interconnected System (SWIS)
The SWIS serves most of WA’s population of more than 2 million with approximately half of the total electricity
consumed in WA delivered via the SWIS. Some basic characteristics are listed in Table 5.
Table 5
SWIS Snapshot
Category
Characteristics
Demand
Peak demand of 3.7GW (January 2014)
Annual electricity generation of 18.3 TWh (2013-14)
1 million customers
Supply
Installed generation capacity of 5.5 GW, including 3 GW of base load capacity
72 registered generation facilities and 25 registered Demand Side Management
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Category
Characteristics
facilities
Networks
1 distribution and transmission network (Western Power)
Connection Rules
Wholesale Electricity Market (WEM) Rules
Available on the Independent Market Operator (IMO) website:
http://www.imowa.com.au/market_rules.htm
Technical Rules
Available on the Western Power website:
http://www.westernpower.com.au/aboutus/accessArrangement/Technical_Rules.html
Source: (IMO, 2014)
The transmission and distribution networks in the SWIS are owned and operated by Western Power (see Figure
5). The majority of relevant technical standards for new connections in the SWIS are outlined in Western Power’s
Technical Rules.
The Wholesale Electricity Market (WEM) operating in the SWIS is operated by the Independent Market Operator
of Western Australia (IMO WA) under the WEM Rules. This market features separate capacity and energy
mechanisms.
Figure 5
Map of SWIS
Source: Perth Energy
As in the NEM, the majority of electricity production in the SWIS is via coal-fired generation however, in recent
years gas-fired and renewable generation have taken a more prominent role. Gas shortages have proven
problematic for the SWIS in the past, motivating an interest in fuel diversification and the installation of dual-fuel
capable plant.
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Figure 6
Proportion of generation in the SWIS by fuel type, 2011
Source: (IMO WA, 2014)
3.4
Australia’s fringe-of-grid market
Fringe-of-grid areas are very remote and serve areas with extremely low population densities. 98 per cent of
Australia is supplied electricity using its on-grid networks which service huge geographic areas. The large
distances between electricity generators and fringe-of-grid areas leads to large transmission and distribution
electrical losses. Distribution Loss Factors (DLF) and Marginal Loss Factors (MLF) can be up to approximately
10% and 14.5% respectively (AEMO, 2013).
Consumers in these fringe-of-grid regions often only pay a subsidised tariff provided to NSP through Community
Service Obligation (CSO) payments supplied by State and Territory Governments. Through consultations it was
highlighted that there is a growing necessity by State and Territory Governments to minimise ongoing CSO
payment or at least obtain greater cost reflective understanding of the cost to supply remote regions of Australia.
Figure 7
NSP Average Network Customer Density
Sources: (AER, 2013), (Western Power, 2014), (Horizon Power, 2014), (Power and Water Corporation, 2013)
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Many fringe-of-grid areas also experience regular power interruptions and power quality issues, and the capital
and operational costs in these low density areas are significantly higher than in urban areas. Reports such as the
Decentralised Energy Roadmap (Intelligent Grid Research Cluster, 2011) highlight the benefits of distributed
energy generation to reduce network expenditure. Electricity storage incorporated with renewable systems has
the potential to address voltage and current fluctuation problems often experienced on radial and Single Wire
Earth Return (SWER) network areas. Ergon Energy trialled the deployment of Grid Utility Storage Solutions
(GUSS) on its SWER networks, with GUSS options breaking even in SWER locations and further deployment
planned across feasible locations. (Ergon Energy, 2014).
3.5
Australia’s Off-grid Electricity Market
As previously mentioned this paper defines ‘off-grid’ as any isolated or islanded system (including private
systems) or interconnected system that is not part of the National Electricity Market or the South West
Interconnected Network.
3.5.1
Overview
Only 2 per cent of Australia’s population live in the off-grid energy market and the off-grid electricity market
currently consumes over 7 per cent of the country’s total electricity demand. It is estimated that 15,575 GWh of
electricity was produced by off-grid generation in Australia in 2012 (BREE (a), 2013) supplied through a total
installed capacity of approximately 5GW. The off-grid energy market sources 78 per cent of its energy from
natural gas and the remainder mostly from diesel fuel. It is the most costly supplied electricity. However, it is also
the least emission intensive of all of Australia’s electricity markets even though only 2 per cent of electricity is
currently generated from renewable sources.
Consumers in the off-grid electricity market include agricultural processing facilities, outstations, remote mines,
small communities, and remote infrastructure such as telecommunication and desalination facilities.
Much of the off-grid electricity market has experienced an increase in demand in recent years associated largely
with the mining industry’s expansion. In line with ARENA’s RAR Program, this paper investigates two main market
sectors:
-
Off-grid Industrial Sector: The industrial and commercial regional energy market, dominated by the off-grid
mining segment and including defence, agricultural and tourist facilities with renewable energy opportunities
greater than 1 MW including those connected to off-grid interconnected systems.
-
Off-grid Community Sector: The community market, which includes small and small off-grid communities,
mining towns, and small commercial facilities with renewable energy opportunities between 100kW and
1MW including those connected to off-grid interconnected systems.
The off-grid industrial sector consumes approximately 12.4TWh per annum or 79 per cent of the total off-grid
electricity produced (excluding NSW, ACT, VIC and external territories of Australia for confidentiality reasons), of
which the majority is consumed by the remote mining industry. There has been a recent trend toward higher
energy intensity which has risen at an average of 2.3 per cent per annum between 1990 and 2010. Similarly,
electricity demand has grown associated with the increasing use of energy for mining exploration activity and the
need to exploit deeper and lower grade ores. Australia’s mining industry is currently facing rising production costs,
global competition and increasing pressure from regulators to improve environmental performance. These factors
are motivating many mining companies to focus more on managing operational energy costs. Renewable energy
is a viable means of providing both fuel savings and energy security.
The off-grid community energy sector is made up of two main sub-sectors: off-grid systems managed by state
and territory owned NSP’s such as Horizon Power (WA), Ergon Energy (QLD), Power and Water Corporation
(NT) and independent off-grid systems managed by the community or an independent power provider.
The Northern Territory has the largest electricity off-grid community demand, accounting for 59 per cent of
Australia’s off-grid community electricity consumption1. Off-grid communities are supplied power through a
1
59% excludes NSW, ACT, Victoria – however, these States/Territories make up very small proportions of the off-grid market
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combination of liquid fuel, gas and hybrid renewable plant on reduced tariffs subsidised through Community
Service Obligations and consume approximately 3.4TWh per annum or 21 per cent of the total off-grid electricity
(excluding NSW, ACT, Victoria and external territories of Australia for confidentiality reasons). Network Service
Providers or independent system operators who operate and maintain these off-grid energy systems are likely to
seek to minimise the current high costs to supply power to off-grid communities and renewable energy is
commonly understood to be part of the solution.
As can be seen from Figure 8, the distribution of existing off-grid generation in Australia is largely constrained to
Western Australia, Northern Territory, Queensland and South Australia. These states are therefore the primary
focus of this study.
Figure 8
Off-grid generation in off-grid Australia
Source: AECOM, based on Geoscience Australia 2006 and 2012 power generation database.
3.5.2
Existing off-grid generation
A summary table of these states is presented in Figure 9 showing the existing distribution of off-grid generation
types. It demonstrates that natural gas and liquid fuels dominate off-grid generation. Natural gas includes LNG,
CNG and LPG. Liquid fuels include diesel, heavy fuel, kerosene and biodiesel. It is assumed that diesel makes up
a significant portion of the liquid fuels category and that biodiesel is unlikely to be a significant portion of the liquid
fuels category.
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Figure 9
Distribution of Off-Grid Generation by State and Territory
Source: AECOM extrapolated from data obtained from Geoscience Australia and BREE 2013. Note: Data quality is arbitrary and may be
inaccurate.
Note that liquid fuels can include biodiesel however a significant proportion of liquid fuels is expected to be diesel.
Off-grid industrial and community sectors are currently supplied with electricity from either off-grid interconnected
systems or islanded power stations. There are already a number of electricity generators servicing off-grid
communities and the industrial sector including; Ergon Energy, Horizon Power, Verve Energy (now Synergy),
Power and Water Corporation (for more detailed discussion of these organisations refer to section 7.0). There are
also numerous privately owned and operated off-grid electricity generation systems ranging from single household
generators to large scale industrial power stations for mines and processing facilities.
Table 6 summarises the electricity demand of the off-grid industrial and communities sector. The mining sector
represents the majority of the off-grid electrical demand in Australia and is likely to be the key driver behind future
growth in off-grid electricity demand.
Table 6
Distribution of demand from the off-grid industrial and communities sectors
Community
State
Industrial
Consumption (GWh)
Share
Consumption (GWh)
Share
South Australia
40
17%
196
83%
Queensland
378
11%
3,021
89%
Northern Territory
1,927
59%
1,347
41%
Western Australia
999
11%
7,881
89%
Tasmania
22
96%
1
4%
3,366*
21%*
12,446*
79%*
Total
Source: AECOM extrapolated from data obtained from BREE 2013
*Excludes NSW, VIC, ACT and external territories of Australia for confidentiality reasons
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Generation in the off-grid industrial sector is characterised by non-renewable thermal generation facilities fuelled
by natural gas or liquid fuels (e.g. diesel, heavy oil). Refer to section 6.0 for more discussion on the off-grid
industrial sector.
Existing generation for off-grid communities on islanded systems are predominantly diesel fuelled. Refer to
section 7.0 for more discussion on the off-grid communities sector.
Generation associated with off-grid interconnected systems is predominantly fuelled by natural gas as shown in
Table 7. A number of off-grid interconnected systems exist in Australia and the dynamics, challenges and
opportunities within these systems will often be very different from those not connected to these off-grid
interconnected systems. Off-grid interconnected systems are discussed in more detail in section 5.0.
Table 7 shows a breakdown of existing off-grid generation fuel types for each region during 2011-2012 and the
distribution of off-grid generation by capacity and total percentage.
Table 7
Capacity and percentage distribution of off-grid generation by region
Generation by Fuel Type
Natural Gas
Liquid Fuels
Wind
Solar
Region
Other
Renewables
Total
MW
Share
MW
Share
MW
Share
MW
Share
MW
Share
964
97.1%
29
2.9%
-
0.0%
0.2
0.0%
-
0.0%
993
1,446
66.7%
676
31.2%
9.6
0.4%
0.9
0.0%
36
1.7%
2,169
Darwin to Katherine
Interconnected
System
409
90.6%
41
9.1%
-
0.0%
0.1
0.0%
1.1
0.2%
451
Rest of Northern
Territory
193
40.1%
286
59.5%
0.1
0.0%
1.7
0.4%
-
0.0%
481
Mount Isa Grid
415
91.4%
39
8.6%
-
0.0%
-
0.0%
-
0.0%
454
Remainder of OffGrid Queensland
130
54.6%
107
45.0%
0.5
0.2%
0.3
0.1%
0.1
0.0%
238
Off-Grid South
Australia
40.0
52.3%
35.0
45.8%
0.3
0.4%
0.2
0.3%
1
1.3%
77
-
0.0%
9
74.4%
2.9
24.0%
0.2
1.7%
-
0.0%
12
17
93.9%
-
0.0%
1
5.5%
0.1
0.6%
-
0.0%
18
3,614
73.9%
1,222
25.0%
14
0.3%
4
0.1%
38
0.8%
4,892
NWIS
Rest of Off-Grid
Western Australia
Off-Grid Tasmania
Rest of Off-Grid
Australia
Total
Source: AECOM extrapolated from data obtained from Geoscience Australia and BREE 2013. Note: Data quality is arbitrary and may be
inaccurate. Liquid fuels can include biodiesel however a significant proportion of liquid fuels is expected to be diesel.
3.5.3
Value proposition for off-grid renewable energy
Australia has a large renewable energy potential, including some of the best wind and solar resources in the world
as well as large land areas available to renewables. The highest solar irradiance levels of the country are
experienced in the North and Central off-grid regions of Australia.
Approximately 5GW of gas and liquid fuel power plants supply electricity to off-grid communities, infrastructure,
mining towns and mines in Australia. Electricity demand in off-grid regions is expected to continue to grow, driven
by the rapid development of mines and mining cities. A number of these energy projects are likely to benefit from
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off-setting their fuel costs and mitigating their security of supply risks by hybridising the existing plant with
renewable energy (as highlighted in section 3.4.4.1).
Wind and solar PV are the two most mature technologies available and are likely to capture the largest share of
the off-grid renewable energy potential. It has been estimated that approximately 150 - 200MW of solar PV and
wind is already feasible and may only require a minimal subsidy in some locations (as highlighted in section 3.5.4
below).
It is expected that the ARENA RAR program will help the development of the off-grid renewable energy industry
and help overcome the challenges in developing and financing these projects. Other government programs which
will contribute to the integration of renewables into the off-grid energy mix include the CEFC and others outlined
further in section 4.0.
3.5.4
Australia’s off-grid renewable market size and distribution
AECOM has estimated the market size potential for integrating renewables into Australia’s existing off-grid
electricity market through a forecasted high and low penetration potential as shown in Table 8. The establishment
of ARENA’s RAR and the continuation of the Renewable Energy Target was assumed, in addition to future
renewable technology development which will further enable uptake.
AECOM utilised information from Geoscience Australia and the Bureau of Resources and Energy Economics
(BREE) to define a primary estimate of the potential market size for off-grid renewable energy especially in
hybridised systems. Geoscience Australia has developed two consolidated datasets of Australia’s existing
generation capacity (one in 2006 and another in 2012). Although some anomalies were identified, these datasets
provided a useful approximation of the minimum existing off-grid capacity – the majority of diesel plants with a
capacity below 500kW were not presented in Geoscience’s dataset. Therefore, where possible, AECOM manually
added the community diesel-fired plants owned and operated by the state owned service providers.
Table 8
Estimated off-grid renewable market size by Region (MW)**
Existing Generation
Renewable Potential
Liquid
Fuels*
Gas
Low
Penetration
High
Penetration
NWIS
29
964
27
166
Rest of Off-Grid Western Australia
676
1,446
104
502
Darwin to Katherine Interconnected
System
41
409
14
82
Rest of Northern Territory
286
193
33
145
Mount Isa Grid
39
415
14
82
Remainder of Off-Grid Queensland
107
130
14
64
Off-Grid South Australia
35
40
5
20
TAS
Off-Grid Tasmania
9
-
1
4
Other
Rest of Off-Grid Australia
-
17
0
3
1,222
3,614
150 - 200
1,067
State
Region
WA
NT
QLD
SA
Total
Source: AECOM extrapolated from data obtained from Geoscience Australia and BREE 2013. Note: Data quality is arbitrary and may be
inaccurate.
* Note that liquid fuels can include biodiesel however a significant proportion of liquid fuels is expected to be diesel.
** AECOM acknowledges that the datasets used to define the market size has anomalies and therefore is not complete. As such, the
figures presented above table are subject to significant uncertainty and only intended to provide a high-level estimate of the minimum
existing diesel and gas capacity and off-grid renewable market potential in the Australia.
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The low penetration case represents a penetration capacity potential of 20 per cent for liquid fuels and 5 per cent
for gas-fired existing power stations, with half the project sites assumed to be technically feasible for hybridisation
(e.g. site constraints). This represents approximately 4 per cent of the current total off-grid installed capacity.
The high penetration case represents a penetration capacity potential of 50 per cent for liquid fuels and 20 per
cent for gas-fired existing power station, with four out of five project sites assumed to be technically feasible for
hybridisation. This represents approximately 22 per cent of the current total off-grid installed capacity.
At low penetrations, small-scale wind and solar PV is already viable (assuming the STC upfront discount) in some
locations if hybridised with diesel generated electricity as there are minimal additional integration costs. When
higher penetrations are targeted, financial support from ARENA or other programs is currently required to make
the project commercially viable due to the high cost of integration technologies. Non-financial drivers such as
energy security or the desire to reduce greenhouse gas emissions may also come under consideration. In
addition, gas is presently cheaper than diesel and, therefore, the business case for integration with gas plants is
not as commercially attractive as for diesel. Nonetheless, with ARENA’s financial support and an expected
increase in gas costs, the business case is expected to improve in the future.
In the longer term, renewable energy penetration is expected to increase as a result of cost reductions in new
renewable and enabling technologies (such as energy storage), fuel price volatility and improved access to skilled
labour as well as greater confidence in the reliability of integrated hybrid systems.
Figure 10
Estimated off-grid renewable market size by Region (MW)
Source: AECOM extrapolated from data obtained from BREE 2013.
Based on these assumptions, the off-grid renewable energy market for the low penetration case is estimated at
approximately 150 - 200 MW. Using BREE data (BREE, 2012) and accounting for assumed learning curves and
technology cost reductions in the past year, an assumed average capital cost of integrating renewables into
remote locations of AUD $3 million per MW was used to estimate a market potential of approximately $450 $600 million for off-grid renewable energy in the short term.
In the longer term, the off-grid renewable energy market for the high penetration case could grow an additional
estimated 850 MW. Assuming the average cost of renewables and energy storage will reduce and based on an
assumed average capital cost of integrating renewables into remote locations of AUD $2 million per MW, this
corresponds to a potential additional $1.7 billion of investments in the off-grid renewable energy market in
the longer term.
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Overall, Australia’s off-grid renewable energy market could total an estimated 1 GW and lead to
approximately over $2 billion in investments with a focus being primarily on states such as Western
Australia, the Northern Territory and Queensland as shown in Figure 10.
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Figure 11
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3.5.5
Stakeholders consultations
In 2013, AECOM completed a consultation with more than 30 industry and government stakeholders. A number of
common themes emerged from our discussions. ARENA’s RAR program has undoubtedly heightened the interest
from some segments of the markets, whilst others remain cautiously observing the sector. Table 9 below
summarises our discussions.
3.5.5.1
Table 9
Key observations from stakeholder consultations
Key observations from Off-grid renewable market
Off-grid Community Market
Off-grid Industrial Market
Key Findings
Project Size
Small (<100kW)
Larger (<10MW)
Key Stakeholders
Network Services Providers, State
Governments, Regional Service Provider
to off-grid communities
Miners, Network Services Providers
Market Maturity
Maturing
Varies
Configuration
Primarily hybrid systems but varies
Renewable penetration
Typically below 30 per cent of existing capacity, some projects up to 80%
Government Support
Programs
-
ARENA RAR Program (Community
Stream)
CEFC
Renewable Energy Target
(SRES and LRET)
-
Community service obligations mean
the off-grid community sector is
already highly subsidised and
renewables may provide an
incentive to reduce the operating
costs associated with existing offgrid generation plant
The Department of Social Services’
“Closing the Gap” initiative (formerly
Department of Families, Housing,
Community Services and Indigenous
Affairs) is driving energy load growth
in indigenous communities
Regional population growth is
generally limited to regions
associated with mining activity
In some cases (Islands in particular),
the transport of food and other
goods to the community is
subsidised by the transport of fuel
-
-
ARENA RAR Program (Industrial
Stream)
CEFC
Renewable Energy Target
(SRES and LRET)
Observation
Market Specific
Observations
-
-
-
-
Common Observations
-
-
-
-
-
Lack of confidence in the ability of
renewable energy systems to supply
electricity in a reliable way
Corporate, emissions and fuel saving
drivers are all secondary to power
reliability and Occupational Health &
Safety
Load profile and energy demand
requirements vary from mine to
mine.
Limited resources to focus on the
integration of renewables
Renewables are not core business
Electricity supply solutions in the off-grid applications have traditionally been
through the use of diesel and gas-fired generators, which provide reliable and
flexible electricity supply
Generally hybrid opportunities exist as a fuel offset exercise, rather than carbon
abatement or demand management means
Every project is different. Integration methodologies vary and generally the
technical issues aren’t well understood
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Off-grid Community Market
-
Off-grid Industrial Market
Project opportunities tend to be small (<5MW) and are at early stage
The market is only now emerging in Australia representing a limited general
understanding of the challenges and opportunities
The market is cautiously excited with respect to ARENA’s RAR Program and first
movers will likely have an advantage
As well as unique project opportunities, the major focus will be on integrating wind
or solar PV as the technology of choice
Intermittency and reliability concerns exist where the system is isolated (i.e. not
interconnected) which limits confidence in adopting higher penetrations
The global and Australian economic downturn has affected many companies
attitude to risk, investment and non-core activities
-
Consulting with key Government, suppliers, end-users and other stakeholders
early in the project is essential to success
-
Size of individual projects tend to be
small which makes it unappealing for
a number of developers
Access to capital can be an issue
Projects are usually commercially
viable only at low renewable energy
penetration, which further limits the
opportunity size
Challenges
Market Specific
Challenges
-
-
-
-
-
-
-
Common Challenges
-
-
Intermittency and reliability concerns
limit high penetrations and perceived
risks associated with renewables
need to be addressed
Energy costs are generally a low
priority for miners and rapid
production is the key focus
There often remains a disparity
between mine life and the renewable
plant’s useful life
Split incentives exist which provide
disincentives to renewable or energy
efficiency uptake
Diesel and gas are well understood
while there is limited knowledge and
know-how for off-grid renewable
energy
Sustainability and cost reductions
are generally not the primary driver
Opportunity costs for mining
companies of diverting resources
from non-core activities are high
Limited economies of scale due to the size and remoteness of most projects
Isolation of project locations can inflate construction and maintenance costs
Commercial models vary and the experience of the financing market in the off-grid
renewables sector is limited
Renewables are perceived by some stakeholders as innovative and not
mainstream
Some renewable technologies (and enabling technologies) are still at an early
stage of commercial development
Limited high quality resource monitoring data available that can be verifiable for
long term forecasts, which is required to finance projects
Financing renewable projects must consider the unpredictable renewable
resource, which can impact performance and project returns. Many financiers
generally understand this for mature technologies such as wind and solar,
however other underdeveloped technologies will likely find it difficult to obtain
project finance
Renewable energy integration into remote area power systems is not core
business for many end users or off-grid interconnected system operators
Reliability in remote locations of renewables that can experience harsh climatic
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Off-grid Community Market
-
3.5.5.2
Off-grid Industrial Market
conditions remains a risk
Gas, LNG, CNG and grid extensions have and will compete with renewables in
the off-grid energy market
Low renewable penetration limitations determined by control logic design products
available and existing plant configurations limit investment returns
Market opportunities
The Australian off-grid renewable energy is an untapped market with large potential. It offers a variety of
opportunities for businesses and government for future growth and development. Table 10 below categorises the
key opportunities identified through the research and industry consultation conducted.
Table 10
Key opportunities and recommendations for stakeholders
Opportunities
Hybridisation
Hybridised generation systems represent the greatest potential area of growth in the
off-grid renewable market.
The greatest opportunity for hybridisation exists where fuel costs are high (typically
diesel-fired generation) and where there is a fuel supply security risk, which is common
in remote locations, which are subject fuel access restrictions as a result of severe
weather events.
Industrial / Mining
Growth Regions
Western Australia’s Pilbara, Mid-West and Great Southern Region currently have over
3.1GW of off-grid generation capacity and thereby represent a large proportion of the
market
System Integration
As the penetration levels of renewables increases in hybridised systems, the integration
costs increase. There is a range of energy storage and control technologies available to
support reliable operation of variable renewables. However, more system integration
experience and expertise is required.
Community Growth
Regions
The Darwin, Katherine, Alice Springs and Tennant Creek regions all represent an
opportunity for greater off-grid renewable development. Similarly mining towns such as
Roxby Downs (SA), Weipa (Qld), Karratha (WA), Newman (WA) and others in the
Pilbara have shown significant load growth as a result of fly-in-fly-out and permanent
regional population expansion.
Interconnection
As the population grows and development continues in off-grid mining regions, there is
an opportunity to develop the existing interconnected systems and link the adjacent
islanded grids. This will also enable larger projects to be developed thereby enabling
economies of scales and increasing the incentive to invest.
Skill Building
As more renewable plants are constructed in regional Australia there will be a need for
skilled labour to design, build, operate and maintain these facilities. Training of
resources in close proximity to the installations will be essential.
Aggregation of small
projects
Many of the project opportunities correspond to small or very small plants. Aggregation
of loads or project opportunities in a region will likely bring economies of scale in both
construction and operation. The state owned Network Service Providers could provide
a natural opportunity for amalgamating a number of community projects. Similarly some
regional organisations such as the Pilbara Cities and Regional Development Australia
initiatives may support the development of regional renewable precincts.
Technology
Development
One of the biggest challenges in off-grid applications is the impact of the intermittent
nature of many renewable technologies on power reliability. There will be a need for
technologies that enable the integration of renewable energy in existing diesel or gas
systems in a reliable yet cost effective way.
Perhaps the most promising technology is batteries, where significant technology
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Opportunities
improvements and developments are being made. Batteries can provide solutions to
short-term and long-term intermittency.
The off-grid market is still relatively immature with a number of challenges discussed throughout this paper. Many
of the early projects may have to bear a cost premium associated with the lack of integration experience and track
record in Australia. Additionally non-cost barriers are likely to represent extra challenges for first movers. As the
industry develops, it will inevitably develop further capacity and costs will decrease. It was clear from the
consultations that the success of a few projects will increase confidence and act as a catalyst for future projects.
The territory and state governments currently subsidise the supply of electricity in off-grid locations through
Community Service Obligations. Reducing the cost of supplying electricity in off-grid locations will reduce the
subsidies required to maintain affordable electricity prices. This opportunity is discussed in depth in Chapter 7.0
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4.0
Government Legislation, Policies and Programs
4.1
National energy policy in Australia
Australia’s energy policy framework is being developed by the Federal Department of Industry (formerly the
Department of Energy, Resources and Tourism) in the Energy White Paper. It will cover the following themes:
-
Competitiveness and growth
-
International trade
-
Energy pricing
-
Reducing regulation
-
Energy Efficiency
-
Renewable and alternative energy
With regard to renewable and alternative energy, the Government intends to consider measures that encourage
the deployment of renewable energy in addition to low emission technologies that allow Australia to continue to
use its abundant coal and gas resources. The Government will also consider removing any barriers to increases
in the use of low emission and alternative transport fuels. (Department of Industry, 2013)
Energy policy reform is also managed via the Council of Australian Governments (COAG), the peak
intergovernmental forum in Australia. COAG comprises the prime minister, state premiers, territory chief ministers
and the president of the Australian Local Government Association. Its role is to initiate, develop and monitor the
implementation of policy reforms that are nationally significant and that require cooperative action by Australian
governments. These reforms include energy market reform, which is managed via the Standing Council on
Energy and Resources (SCER), formerly the Ministerial Council on Energy (MCE).
4.2
Australia’s Direct Action Plan
With the repeal of the Clean Energy Act 2011, the Government plans to meet Australia’s emissions reduction
target through the Direct Action Plan to achieve a reduction in carbon emissions of 5 per cent below 2000 levels
by 2020. The Direct Action Plan is comprised of The Emissions Reduction Fund and Solar Towns as described
below. This is in addition to pre-existing initiatives that aim to drive innovation and investment in renewable energy
such as the Renewable Energy Target, the Clean Energy Finance Corporation (CEFC) and the Australian
Renewable Energy Agency (ARENA).
4.2.1
Emissions Reduction Fund
A major part of the Government’s Direct Action Plan is the Emissions Reduction Fund. The aim of this initiative is
to allow businesses, local governments, community organisations and individuals to complete approved
emissions reduction projects and to seek funding from the Government for those projects through a reverse
auction or other purchasing process.
It was designed by the Department of the Environment and legislation on this fund has yet to be passed. The
principles of the fund are:
-
Lowest cost emissions reductions – to identify and purchase emissions reductions at the lowest cost;
-
Genuine emissions reductions – to purchase emissions reductions that make a real and additional
contribution to reducing Australia’s greenhouse gas emissions;
-
Streamlined administration – to be easy for businesses to participate.
4.2.2
Solar Towns
The Government’s has allocated $2.1 million over three years from 2014-15 to support community groups, such
as sports clubs, seniors' clubs and scout centres, to support the installation of solar photovoltaic and solar hot
water systems in the electorates of Corangamite, Bendigo and McEwen in Victoria, Moreton and Bonner in
Queensland and Lyons in Tasmania. Grants will also be available to community groups in the City of Monash in
Victoria and the Port Adelaide/Wakefield/Makin area in South Australia. (Australian Government, 2014)
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4.3
Other major initiatives
Other initiatives, including the Renewable Energy Target (RET), the Clean Energy Finance Corporation (CEFC)
and the Australian Renewable Energy Agency (ARENA) have been developed to complement the RET scheme.
The RET, ARENA and CEFC have been designed to support new technologies through the innovation and
commercialisation chain.
4.3.1
The Renewable Energy Target (RET)
Australia has a Renewable Energy Target (RET) of 20 per cent by 2020, implemented via a renewable certificates
mechanism. The Clean Energy Regulator oversees the implementation of the RET scheme while the Department
of Environment (formerly the Department of Climate Change and Energy Efficiency) manages national policy and
the legal framework.
Since 2011 the RET has operated in two parts:
1)
Large-scale Renewable Energy Target (LRET) – encourages the development and implementation of
large-scale renewable energy projects such as wind farms. Large renewable generators produce Largescale Generation Certificates (LGCs).
2)
Small-scale Renewable Energy Scheme (SRES) – supports the installation of small-scale systems
including solar systems which are typically under 100kW for small-scale solar PV panels or 6.4kW for hydro
and 10kW for wind and also includes solar water heaters (Department of Climate Change and Energy
Efficiency, 2013). Small renewable generators produce Small-scale Technology Certificates (STCs).
Most renewable energy systems are eligible to create LGCs or STCs corresponding to the amount of MWh
produced, regardless of whether they are grid-connected or off-grid. Combined, the two parts are intended to
deliver in excess of 45,000 GWh of renewable energy in 2020 (Department of Climate Change and Energy
Efficiency, 2013).
The RET policy legislates obligations on electricity retailers and other liable entities to source a proportion of their
electricity from renewable energy sources. The Renewable Power Percentage (RPP) of liable entities increases
each year to 2020 and then remains constant to 2030. Liable entities have to procure and surrender certificates
(LGCs and STCs) from the market to meet their obligations.
The LRET is the key driver for the development of wind farms in Australia, which are meeting the majority of LGC
requirements since they are currently the cheapest form of renewable energy. Looking forward, the market price
for LGCs is broadly expected to represent the premium paid for renewable energy compared to the average
wholesale price for electricity in the NEM. The estimated volume weighted average market price for a LGC was
AU$38.69/MWh in 2013.
Small-scale systems are eligible to receive all STCs for renewable energy deemed to be created over the life of
the plant upon installation of the system. This provides a reduction in the capital investment required and
minimises administrative overheads.
The Federal Government has recently conducted a review of the Renewable Energy Target. The outcome of the
review is not expected until 2015.
4.3.2
Australian Renewable Energy Agency (ARENA)
ARENA was established in 2012 as an independent agency with the primary objectives to improve the
competitiveness of renewable energy technologies and increase the supply of renewable energy in Australia
(ARENA, 2013). ARENA's $2.5 billion funding is legislated until 2020, providing improved long term funding and
policy certainty for industry.
ARENA’s Regional Australia Renewables (RAR) program is directly relevant to the themes of this paper and it is
discussed in detail in section 4.3.4.
4.3.3
The Clean Energy Finance Corporation (CEFC)
The CEFC has been established by the Australian Government to invest up to $10 billion over five years starting
from 2013-2014 in the commercialisation and deployment of renewable energy, energy efficiency and lowpollution technologies. The CEFC will not provide grants; instead it will invest through a variety of funding tools
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including loans and equity investment. The CEFC has been collaborating with banks and other financing
institutions to provide co-funded loans. The focus has primarily been on loans above $50m, however financial
institutions have recently expressed an appetite for aggregating smaller projects.
ARENA’s Regional Australia Renewables (RAR) program
4.3.4
One key driver promoting the off-grid clean energy market’s growth is the Australian Renewable Energy Agency’s
(ARENA) Regional Australia’s Renewables (RAR) Program. The program intends to provide up to AUD $400
million funding to build 150MW of installed off-grid and fringe-of-grid renewables by 2018. Expressions of interest
were sought from interested parties between June 2013 and December 2013 with the intention to commit all
funding within 2-3 years of June 2013.
The RAR program is split into two separate programs: the RAR – Industry program (I-RAR) and the RAR –
Community and Regional Renewable Energy program (CARRE). These two programs cover two sectors:
-
Industrial and mining sector, supporting demonstration projects greater than 1MW with an aim to prove
the potential and value proposition of renewables in this sector including two or more projects greater than
10MW in scale.
-
Communities sector, which includes interconnected systems supported via Network Service Providers
(NSP) or operated and managed by an independent system operator. Most renewable project opportunities
in this sectors range between 100kW and a few megawatts.
Interconnected systems such as the NWIS, Darwin-Katherine, Mount Isa and others, are considered to be off-grid
systems and renewable energy projects in these locations were eligible for the ARENA’s RAR program.
In addition to the overarching RAR program objectives detailed in the Preamble of this report, the CARRE
program has further objectives of its own. The CARRE program objectives are to:
-
demonstrate technical viability and system reliability of high penetration renewable energy systems in
islanded and mini-grids;
-
facilitate the further development of supporting technologies and systems that will improve renewable energy
reliability and commercial success, such as system integration and stabilisation and storage, through
demonstration and deployment ;
-
demonstrate the commercial viability of innovative business models, including ownership models, for
renewable energy systems in these locations; and
-
develop and share knowledge and experience in implementing, operating and maintaining renewable energy
systems among regional energy suppliers and distributors and commercial and community customers.
4.4
Other support programs
The table below provides an overview of other programs supporting the development of regional renewable
projects in Australia.
Table 11
Remote energy programs
Program
Details
Community Service
Obligations
Electricity supply is considered an essential service and the National Framework for
Energy Community Services Obligations (CSO) is aimed at providing equity in
electricity pricing across Australia (MCE, 2008).
State and Territory
Governments
Diesel Fuel Rebate
Scheme
CSOs are targeted at regional areas of Australia’s electricity requirements.
It is typically delivered by state-owned service providers or independent regional
service providers that gain funding from the state government. It is done under
different programs such as the Remote Area Essential Services Program (RAESP) in
Western Australia, or the Remote Areas Energy Supplies scheme (RAES) in South
Australia.
Under the Diesel Fuel Rebate Scheme, the Australian Government provides a rebate
of the excise and customs duty paid on diesel by various parties, including mining,
agriculture and some remote residential uses.
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Program
Details
Australian Taxation
Office
The primary purpose of the scheme is to maintain competitiveness in key export
industries, such as mining and agriculture, in a manner consistent with the
Government's broader fiscal objectives.
R&D Tax Incentive
The Research & Development (R&D) Tax Incentive is a targeted at assisting
businesses offset some of the costs of doing R&D. It is a broad-based entitlement
program which means that it is open to firms of all sizes in all sectors who are
conducting eligible R&D, including in the energy sector.
AusIndustry
Small-scale
Renewable Energy
Scheme
Clean Energy
Regulator
Renewable Energy
Venture Capital Fund
Southern Cross
Venture Partners
Under the Small Renewable Energy Scheme, renewable solar PV projects under
100kW can generate STCs upfront, which assists with upfront capital costs. Other
renewable energy technologies can be eligible as described in Error! Reference
ource not found..A number of conditions applied, which are described in the RET
website (http://ret.cleanenergyregulator.gov.au/Solar-Panels/Solar-Credits/SolarCredits)
Renewable Energy Venture Capital Fund is a 13 year venture capital fund of $100
million managed by Southern Cross Venture Partners. This investment was matched
by Softbank China Venture Capital creating a $200 million Southern Cross
Renewable Energy Fund. The primary objectives of the fund are to:
-
Increase the number of Australian renewable energy and enabling technology
companies that are successful in Australian and overseas markets;
-
Foster the skills and management capability of Australian renewable energy and
enabling technology companies by providing active investment management;
and
Leverage additional investment in Australian renewable energy technology and
enabling technology companies from the private sector, including from international
sources.
Remote Indigenous
Energy Program
(REIP)
Department of Social
Services
Funding has closed
REIP was part of the Australian Government’s Clean Energy Future Package with
AUD $40 million pledged over four years. The program was to build upon the work
undertaken by Bushlight over the last ten years.
REIP was to provide funding for the deployment of fit-for-purpose renewable energy
systems in up to 50 smaller remote Indigenous communities across Australia.
REIP was planned to target communities with a maximum population of 50 people
and no more than 20 dwellings. REIP was to act to replace the entire diesel
generation system in these communities with a solar installation
RIEP was also to provide energy efficiency education and training in basic system
maintenance to community members and repairs and maintenance to existing
systems (Department of Families, Housing, Community Services and Indigenous
Affairs, 2013).
Bushlight
The Centre for
Appropriate
Technology (CAT)
The program is no
longer funded
The program started in 2002 and is no longer funded. Between 1997 and 1999, the
Australian Cooperative Research Centre for Renewable Energy and the Centre for
Appropriate Technology conducted an audit of renewable energy systems in remote
areas. This research project led to the development of Bushlight in 2002. Bushlight
was a program delivered by the Centre for Appropriate Technology (CAT). The
program focused on the design, installation and maintenance of small renewable
energy systems for remote households and communities. The program was primarily
funded by the Australian Government through the Department of Families, Housing,
Community Services and Indigenous Affairs. Bushlight also received funding from a
range of other sources, including fee-for-service work for discrete projects. The latest
project, in May 2013, was with Tjuwanpa Outstation Resource Centre to share
knowledge and conduct training on renewable energy systems near Hermannsburg,
West of Alice Springs.
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Program
Details
“Since 2002 the Australian Government has provided about $57 million to the
Bushlight program, delivered by the Centre for Appropriate Technology to install more
than 140 renewable energy systems in more than 120 remote Indigenous
communities. Bushlight also provides maintenance services and community training
supporting renewable energy systems in a further 100 communities.” (Department of
Families, Housing, Community Services and Indigenous Affairs, 2013)
Renewable Remote
Power Generation
Program
Closed in 2009
The program was operational between 2001 and 2009. It provided rebates of up to
$500,000 for households, communities, not-for-profit, business, government and
other organisations, to support the installation of renewable generation systems in
off-grid areas. Other sub-programs existed, including the Remote Area Power Supply
Program, the Renewable Energy Water Pumping Program, the Regional Energy
Efficiency Program, the Rural Renewable Energy Program, Large individual projects
off-grid and Industry support projects.
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5.0
Off-grid Interconnected Systems
Many areas defined as ‘off-grid’ in this study are in fact interconnected electricity networks or ‘grids’. These grids
are much smaller than the NEM and SWIS which make up the area defined as ‘on-grid’ in Australia. Nevertheless,
some such as the NWIS and Darwin-Katherine interconnected systems are thousands of kilometres long and are
by no means geographically small by world standards. Gas-fired generation makes up the vast majority of
generation within these isolated interconnected systems.
5.1
Western Australia
Thirty eight networks including two interconnected networks are operated and managed by Horizon Power to
supply electricity to communities and industries in Western Australia. The North West Interconnected System
(NWIS) is the second largest interconnected system in Western Australia after the SWIS (refer to section 3.3),
supplying electricity to mines and the Pilbara. The NWIS has a generation capacity of 400 MW which is mainly
fuelled by natural gas (Energy Action, 2012). While not connected electrically, the SWIS and the NWIS are
connected through gas pipelines.
The NWIS evolved from islanded generation and transmission systems installed in the 1970s to provide electricity
for iron ore mines. These islanded systems were interconnected in 1985 to form the NWIS. Five parties are
involved in the ownership and operation of the NWIS: Horizon Power, Rio Tinto, ATCO Australia, Alinta Energy
and BHP Billiton. Connections to this network proceed under the processes defined by Horizon Power.
Horizon Power reported that 548 GWh were generated in the NWIS in 2012-13 (Horizon Power, 2012-13).
Figure 12
North West Interconnected System (NWIS)
Source: (Horizon Power, 2009)
Horizon Energy also operates the much smaller East Kimberly Interconnected System which supplies electricity to
Kununurra and Wyndham from Pacific Hydro’s 30 MW Ord River Hydroelectric Power Station located 80
kilometres south of Kununurra.
5.2
Northern Territory
The Northern Territory features three regulated systems: Darwin-Katherine, Alice Springs and Tennant Creek.
These supply electricity to over 75,000 customers.
The three regulated systems as well as the power systems of several smaller townships are operated by Power
and Water Corporation (PWC).
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Table 12
Electricity generation in 2011 in the NT regulated markets
Capacity
Demand
Network length
NT Consumption
MW
GWh
km
Share
Darwin-Katherine
433
1,545
4,829
46%
Tennant Creek
17
31
385
1%
Alice Springs
73
187
607
6%
Source: (Northern Territory Government, 2011)
PWC is a vertically integrated power utility managing generation, transmission, distribution and retail. There are
four other generation companies that operate within the PWC managed networks, namely NGT, Cosmos Power
and LMS Generation whose generation is connected to the Darwin-Katherine system, and Central Energy Power
which generates in the Alice Springs system.
The 322MW Channel Island Power Station near Darwin is the largest power station in the Northern Territory and
is connected to the Darwin-Katherine network. Figure 13 highlights all PWC’s power stations (excluding minor offgrid stations operated by Indigenous Essential Services). It must be noted that six power stations (Borroloola,
Elliott, Daly Waters, Timber Creek, Ti Tree and Kings Canyon) located in remote towns are owned and managed
by PWC but are not connected to a regulated market. More than 90 per cent of the electricity generated within
the three PWC regulated markets come from natural gas, while generation in the six islanded towns is largely
diesel-fuelled.
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Figure 13
Power Water Corporation interconnected systems and power stations
Source: (Power Water Corporation, 2013)
5.3
Queensland
The Mount Isa-Cloncurry supply network in North West Minerals Province is Queensland’s only regulated off-grid
interconnected system. It is operated by Ergon Energy and supplies over 10,500 customers in Mt Isa, Cloncurry
and parts of Burke and Boulia. The major focus for the region is mining and minerals processing activities, with a
particular focus on base metals. The region also has a well-established pastoral industry and is becoming an
increasing focus for tourism. Mount Isa, the major city in the region, serves as a transport hub and as a base for
much of the economic and social activity in the region.
The preliminary conclusion of the North West Queensland Energy Demand Working Group in 2008 was that there
is significant potential future energy demand in North West Queensland. To date, the 305 MW gas-fired Mica
Creek Power Station owned and operated by Stanwell Corporation supplies electricity to Mount Isa-Cloncurry
network. Some of the mines also supply their own power – Glencore Xstrata owns two gas-fired power plants
(32MW and 45MW), Incitec Pivot owns 42MW gas-fired power plant to supply Phosphate Hill mine and Energy
Development owns and operates a 38MW plant, which supplies power to BHP Billiton Base Metals. In addition,
the 242MW Diamantina Power Station is currently under construction to supply power to Glencore Xstrata Mount
Isa Mines through to 2030.
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5.4
Renewable energy opportunities in off-grid interconnected systems
5.4.1
Large shopping centres and warehouses
Shopping centres and warehouses consume large amounts of power and will often have large roof space
available to install solar energy. Their electricity demand profile matches solar PV generation well, which enables
the deployment of “behind-the-meter” solar systems. This effectively means that solar power offsets contracted
electricity prices as opposed to generation cost only, which makes solar PV significantly more cost competitive.
According to stakeholders consulted in the Northern Territory, there has been a noticeable change of mindset with
regards to renewable energy. Only half a decade ago, businesses did not show any interest in solar energy and
did not believe it could be a cost competitive solution. Today, a number of large users including shopping centres
and warehouses are looking at solar as a promising solution to cut their electricity cost.
Smaller businesses will usually not have the capital to invest in solar projects, but are more likely to adopt solar
leasing agreements. Larger businesses will have easier access to capital and typically want to own the solar
system, but will usually need a third party to manage the project on their behalf.
Cold thermal storage has been identified as an add-on opportunity in regions such as the Northern Territory and
the Pilbara. It provides cost effective storage and enables higher solar penetration. It provides a good match of
the demand profile of large shopping centres in tropical regions, as half their energy demand is for cooling. The
technology has been successfully deployed on the Charles Darwin University campus in Darwin.
Table 13
Key stakeholders and challenges of large shopping centres and warehouses
Key Stakeholders
Challenges
Large shopping centres with major retailers including:
Target, Coles, Woolworth, Federation Centres,
Bunnings.
Energy is still a secondary concern for most
businesses. Little time is available to investigate
renewable energy opportunities.
The high capital cost is a significant challenge.
5.4.2
Behind-the-meter installations on hospitals, schools, airports
Some parties that are increasingly considering solar as a ‘behind the meter’ solution to offset their electricity
demand include hospitals, schools and airport. In certain cases, the marketing advantage of integrating
renewables can be another important driver.
5.5
Challenges to renewable energy in the off-grid interconnected
systems
The main challenges to the uptake of renewables in off-grid interconnected systems identified in the research and
stakeholder consultations are project economics, competing subsidies and split incentives.
5.5.1
Economics
The interconnected systems are primarily supplied by gas-fired generation, which reduces the competitiveness of
renewable energy.
5.5.2
Opposing subsidies
Off-grid energy supply subsidies such as the Community Service Obligations (CSO) imposed on Network Service
Providers of off-grid interconnected systems and Fuel Tax Credits, together add complexity to the true cost of
supplying energy to remote locations. An overview of some of the subsidies provided to remote grid operators are
set out below for the financial year 2012/13:
Table 14
CSO Subsidy Overview
Organisation
CSO Subsidy
2012/13
Ergon Energy
$400 million
Further Details
Funded by Queensland Government. Queensland State Treasurer
Tim Nicholls was reported in May 2013 to say that the by 2014/15,
“the cost [of CSO’s] is estimated to increase to more than $700
million”. In 2009-10 this subsidy amounted to $250M for Far North
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Organisation
CSO Subsidy
2012/13
Further Details
Queensland (Cairns and Far North Environment Centre, 2011).
Horizon Power
$181 million
Funded by the WA Government from the network charges to
Western Power’s wholesale distribution customers.
Power & Water
Corporation
$63 million
Funded by the NT Government. AEMC estimates that NT
householders pay around 24 to 26 per cent less than the cost
reflective price of electricity. (AEMC, 2012)
Cost reflective pricing may be important to promote more efficient use of energy and improve the utilisation of
infrastructure thereby lowering overall supply costs for all consumers. Renewable energy will likely require further
future Government support if fossil fuels continue to be subsidised by these programs.
5.5.3
Split incentives
As highlighted previously, interconnected systems cover the industry and community segments. These systems
are much larger than off-grid communities and are operated by either Power and Water Corporation (PWC) or
Horizon Power. Mining companies that connect to them can be required to contribute to the investment in new
capacity or pay a relatively higher electricity rate compared to other customers. There is often a lack of clarity
around which party/parties could benefit from renewable energy and therefore who should invest in renewable
energy.
5.6
Off-grid interconnected systems case studies
Some examples of renewable energy projects that have been developed in recent few years are set out in Table
15.
Table 15
Off-grid interconnected systems case studies
Alice Springs’ Solar City
Desert Knowledge Australia Solar Centre
Alice Solar City is a $37 million project designed to
explore how a combination of options including energy
efficiency measures for homes and businesses, solar
technologies, cost reflective pricing and community
education can encourage the residents of Alice Springs
to use electricity more efficiently.
The project was launched in 2008, when there were
only 2 solar systems in Alice Spring. By 2013, 316 solar
PV systems, 908 solar hot water systems and 608
smart meters had been installed on homes and
businesses.
The Desert Knowledge Australia Solar Centre (DKASC)
is a demonstration facility in Alice Springs, which
involves 28 different solar panels. The site is open to
visitors and its website
(http://www.dkasolarcentre.com.au/) offers a range of
information on the installed technology and the real
time and historical performances of the different solar
systems. The objective of the project is to support the
deployment of solar in regional locations through
demonstrating solar technology performance in arid
conditions.
Uterne Solar Farm
Other renewable energy projects
The 1MW tracking system was built in 2011 in Alice
Springs. It was built by SunPower with funding from the
Alice Solar City initiative. At the time of construction,
the system was the largest tracking array in Australia. It
covers over three hectares and consists of 3,048 solar
modules installed across 254 tracking arrays. The solar
farm is expected to produce about 1 per cent of Alice
Springs’ electricity a year and can meet 2 per cent of
peak demand on a sunny day.
Crowne Plaza solar system: 305kW Fixed flat plat PV
system at Crown Plaza, Alice Springs
Alice Springs Airport: 235kWp Tracking concentrated
PV, Alice Springs Airport
Shoal Bay landfill: 1.1MW of landfill gas from Shoal Bay
landfill
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6.0
Off-grid Industrial Market
6.1
Mining sector
6.1.1
State of the market
Electricity consumption in the off-grid industrial market is largely dominated by the demand from the mining
sector. The mining industry experienced unprecedented growth over the last decade and currently represents
approximately 5 per cent of Australia’s energy demand.
Mining investment has boomed in recent years, rising from 1 per cent of nominal output 10 years ago to 4 per
cent at the end of the last decade. In 2012-13, the mining sector accounted for approximately 10 per cent of
Australia’s GDP, employed over 260,000 people and invested AUD$7.1 billion in minerals and petroleum
exploration.
In the year to April 2013, production capacities increased by 100 million tonnes for iron ore, 22 million tonnes for
coal, 4.3 million tonnes for LNG and 2 million tonnes for alumina.
During 1989-90 to 2010-11, energy consumption in the mining sector increased by an average growth rate of 6.3
per cent a year due to a strong increase of mining activity and depletion effects. In 2012-13, energy consumption
in the mining sector grew by 9 per cent, reflecting a transition from investment to production phase of the mining
boom (BREE, 2013).
Ranked number one in the world for mining investment, Australia is a politically and economically stable economy
rich in resources (Behre Dolbear Group, 2012). Australia holds the world’s largest reserves of brown coal, mineral
sands, nickel, lead, silver, uranium, iron ore and zinc. Table 16 shows Australia dominates mineral production and
resources with estimates that current rates of mining production can be sustained for many decades.
Table 16
World ranking of Australia's mineral production and resources for 2009 (Source: (Geoscience Australia, 2012), (Austrade,
2014))
Commodity
Production Rank
Resource Rank
Lead
2
1
Nickel
4
1
Copper
5
2
Zinc
2
1
Manganese Ore
2
4
Diamond
5
3 (industrial diamond)
Silver
5
1
Gold
2
1
Black Coal
4
5
Brown Coal
5
1
Rutile
1
1
Zircon
1
1
1
1
Energy Intensity
Base Metals
High
Precious Metals & Diamond
High
Coals
Moderate - High
Mineral Sands
High
Other
Iron Ore
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Commodity
Production Rank
Resource Rank
Bauxite
1
2
Lithium
2
3
Niobium
Not Known
2
Tantalum
Not Known
2
Uranium
3
1
Energy Intensity
The mining industry is a major contributor to Australia’s economic prosperity, contributing close to 60 per cent of
the annual value of total goods exports ($176 billion) in 2012-13 and generating $12.7 billion in new private capital
expenditure, an increase of 15.5% compared to the previous year (Austrade, 2013). This is supported by free
trade agreements in the global marketplace for the exportation of goods on a commercial basis to Australia’s
major mineral export markets including Japan, China, Korea and India.
In existing mines, energy can correspond to a large share of a mine’s operational cost with crushing, grinding and
hauling ores the top three operational costs of a mine (Bloomberg, 2012). The most energy intensive mining
processes are illustrated below:
Figure 14
Energy intensive processes during the mining production chain
Exploration
Extraction
• Blasting
• Drilling
• Digging
• Ventilation
• Dewatering
Materials
Handling
• Diesel
• Electric
Beneficiation
& Processing
• Crushing
• Grinding
• Seperation
Transportation
6.1.2
Market outlook
The rapid growth of the mining sector weakened during 2012-13, creating a significant impact on the Australian
economy. Australia’s mining industry is facing rising production costs and global competition, declining grades of
ores that are increasingly complex to process, and increasing pressure from regulators to improve environmental
performance. As a result, the mining industry has reduced new investments and put many large projects planned
on hold.
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Despite the recent slowdown of mining investments, Australia still features a large pipeline of projects. Significant
opportunities still exist for off-grid renewable investment in the Australian resources and energy sectors,
particularly in reducing costs even though there remain challenges in realising these opportunities.
As of October 2013, there were 63 mining projects in Australia at the committed stage (lifetime CAPEX value of
$240 billion) and 162 projects at the Feasibility Stage (lifetime CAPEX value of $208 billion) (BREE, 2014).
Liquefied natural gas (LNG), gas and oil projects are dominating Australia’s investment program with AUD $195
billion in committed investments (81 per cent of committed investments) (BREE, 2013).
Table 17
Summary of Mining projects in the investment pipeline, October 2013
Publicly Announced
Feasibility Stage
No. of
Project
s
No. of
Projects
Range
AUD $b
Value
AUD $b
Committed
No. of
Projects
Completed
Value
AUD $b
Aluminium, Bauxite,
Alumina
3
1-2
3
2.0
Coal
19
16.9 – 19.6
50
54.1
15
11.4
Copper
5
10.2 – 11.4
9
3.2
2
0.3
Gold
9
1.1 – 1.8
10
2.1
4
Infrastructure
10
14.8 – 23.5
17
28.2
Iron ore
19
35.8 – 55.8
22
Lead, Zinc, Silver
2
0.1 – 0.5
LNG, Gas, Oil
9
Nickel
No. of
Projects
Value
AUD $b
5
5.1
0.5
2
0.9
11
12.0
4
8.7
39.6
9
17.3
1
5.2
3
0.5
4
1.9
24.5 – 26.8
9
62.7
14
195.0
5
10.2
4
2.0 – 4.0
7
5.9
Uranium
5
1.4 – 2.4
2
0.6
1
0.1
Other Commodities
7
2.0 – 4.0
30
9.6
3
1.5
1
0.3
Total
92
110 – 152
162
208
63
240
18
30
Approximate breakdown by state
Western Australia
39
56.0 – 86.0
50
72.3
24
121.8
8
20.5
Queensland
24
20.6 – 27.4
64
99.2
19
77.4
4
4.8
Northern Territory
& South Australia
13
1.1 – 13.9
11
7.7
4
33.6
2
0.5
NSW
11
5.6 – 7.3
25
12.9
15
6.4
2
1.3
Victoria and
Tasmania
2
1.6 – 2.1
10
2.3
1
1.0
1
2.6
Source: (BREE, 2013)
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Figure 15
Committed mining investment for projects by Region
Source: (BREE, 2013)
The majority of the mining projects in development are located in Western Australia and Queensland. Twenty-four
projects valued at a total of $122 billion are committed in WA. In the six months to October 2013, eight mining
projects were completed in WA, with an aggregated value of $20.6 billion. Over the last decade, the Pilbara region
of WA has become a regional hub for oil and gas and iron ore projects resulting in an important growth in
population and energy demand in the region.
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Figure 16
Advanced minerals and energy projects – October 2013
Source: (BREE, 2013)
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6.1.3
Energy demand in the mining sector
Mining operations require energy in a variety of forms and for a variety of usages including excavation, grinding,
haulage, ventilation, and dewatering as well as for supporting infrastructure and services. Comminution or
grinding is the largest energy consumer of a mine site requiring up to over 100kWh per ton depending on the
degree of grinding. (Wang, Fengnian, & Manlapig, 2011)
As illustrated in Figure 17, the energy consumption of the mining sector tripled over the period from 1990 to 2010,
corresponding to an average 5.7 per cent average annual growth rate (BREE, 2012). By 2012, the off-grid mining
sector accounted for 12.4 TWh of Australia’s electricity consumption.
The future mining investments discussed in section 6.1.2 suggest that this trend is likely to continue over a
number of years. In particular, the three segments dominating the investment plan are; oil and gas, iron ore and
coal and these also are the three largest energy consumers within the mining industry. Mining regions such as the
Pilbara and Midwest are expected to see their electricity demand soar over the next decade.
Figure 17
Primary energy consumption in the mining sector 2
Source: (BREE, 2012)
The rising energy consumption from the mining sector is the result of an intensification of the mining activity
combined with an increase of the energy intensity of the mining sector.
As illustrated in Figure 18 the energy intensity of the industry has risen at an average 2.3 per cent rate per annum
between 1990 and 2010.
2
Note: The graph shows the net primary energy consumption of (or net primary energy supply to) the mining
sector. The final energy consumption is the net primary energy supply less energy consumed or lost in
conversion, transmission and distribution. In 2009-10, the final energy consumption of the mining sector
amounted 340PJ (out of 509PJ of primary energy supply shown in the graph).
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Figure 18
Trends of intensity and yearly change in energy consumption in the mining sector
Source: (BREE, 2012)
Figure 19 shows that the trend toward higher energy intensity correlates with an increase in the use of energy for
exploration activity and the need to exploit deeper and lower grade ores — particularly base metals such as
copper, nickel, lead and zinc. In addition, the sharp rise in production of relatively energy-intensive liquefied
natural gas (LNG) may have contributed to the increase in energy intensity in the sector in recent years. The
rising commodity prices have also incentivised mining companies to focus on faster mining output rather than
managing operational energy costs.
Figure 19
Average ore grades over time
Source: (CRCORE, n.d.)
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As highlighted in section 6.1.2, the Pilbara region of Western Australia is a growing region for gas and iron ore.
For example Chevron’s Wheatstone gas project and related developments at Onslow are forecasting that demand
will triple by 2016/17, which means a new 9MW power station will be required. In the Pilbara region the energy
demand from the mining sector is expected to increase by 12,000 GWh by 2015. A majority of it is likely to be
gas-fired self-generation. For the Mid-West region of Western Australia, an additional 2,100 GWh per year of new
generation will be required by 2018, of which around 77% will be off-grid. (CME, 2013)
As for other remote renewable energy opportunities within mines, the below three mines use off-grid diesel
generation systems as their prime power source. With the potential for sites to benefit from off-setting their fuel
costs and mitigating their security of supply risks, renewable energy hybridisation could be considered.
Table 18
South Australian mines using off-grid diesel generation systems
Site
Location
Organisation
Plant size (kW)
Jacinth Ambrosia
Yalata
Iluka Resources
6,800
Challenger Gold Mine
-
Kingsgate Consolidated
5,000
Beverly
Beverly
Heathgate Resources
6,000
Source: (GovtSA, 2014)
6.2
Renewable energy in the mining sector considerations
There are a number of challenges that limit the development of renewable energy in the mining sector; some of
which are presented in Table 19 below.
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Table 19
Challenges and opportunities in the mining sector
Challenges
Opportunities
Intermittency and reliability – Mine sites require very
high levels of reliability. An electricity outage can cost
millions of dollars per day in lost revenue from loss of
production, and outages can be extended further due
to the slow time to restart processing and ramp up to
full capacity. Maintaining constant and reliable
electricity supply can also be important from a safety
perspective.
Solar PV and wind hybrid systems can be designed to
meet the reliability requirements of the mining sector.
Solar PV and wind are intermittent by nature, and
therefore can’t ramp-up rapidly.
Renewables can be used to offset diesel or gas usage,
rather than to replace capacity in the system.
At low levels of penetration, intermittent renewable
ramping will remain within the load following capability
of the diesel units. At higher levels of penetration short
term intermittency can be addressed by the use of
flywheels and batteries to allow the existing power
generation units to match.
There is general lack of confidence from the mining
industry that renewable energy can be integrated
reliably to their generation system.
To examine the business case, the appropriate cost
comparison is the operating cost of diesel generation
(mostly composed of fuel costs) against the levelised
cost of integrated solar generation (including control
and integration costs). At low levels of solar
penetration, solar energy still presents a positive
business case in most parts of Australia. See section
8.0 below for further details.
Split incentives – One party may install the generator
while another bears the ongoing fuel costs.
Where the parties have a close commercial
relationship, there are opportunities to agree on
contractual terms, which represent a win-win situation.
This is the case in some interconnected systems
operated by Horizon Power, where the mining
companies have obligations to pay for an agreed power
plant capacity but do not pay the subsequent
operational diesel costs.
Where electricity is generated using diesel, the party
responsible for the ongoing fuel cost may want to
invest into the integration of solar into the system.
A similar situation happens when mining companies
procure their electricity from Independent Power
Producer (IPP), who build, own, operate and maintain
the power system on their behalf. The miner might pay
a fixed electricity rate over a contract term and free
issues diesel to the IPP. Take-or-pay terms are also a
common feature of PPA contracts, which can
complicate matters.
Low priority – Energy costs tend to be a low priority
for the miners whose primary focus is on rapid
production expansion over capital cost savings. There
is also a historical perception of low energy prices.
As costs increase, there is likely to be a growing focus
on energy costs by the mining industry. The current
economic environment and moderation of the mining
investment may also push some of the mining
companies to look at alternative ways to save energy
and costs; while minimising the risks associated with
fuel price volatility.
In light of ARENA’s RAR program, there is a role for
government organisations and private companies to
highlight to the mining industry the economic benefits
of renewable energy.
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Short project timeframes – Renewable energy
projects generally rely upon long operating lifetimes to
achieve cost effectiveness. By contrast, certain mining
projects may not last for that duration, or may have an
uncertain lifetime.
The cost effectiveness of renewables to displace diesel
or gas operation will depend upon the lifetime of the
project, with longer lifetimes allowing cost recovery at
lower delivered diesel or gas prices. Higher delivered
diesel or gas prices or additional project support from
organisations such as ARENA could justify the
integration of PV particularly into projects with shorter
lifetimes. ARENA is focusing on mining projects with a
5 year minimum lifetime.
Portable systems are now available on the market, and
these may prove suitable for some applications. This
would allow a PV system to be integrated into the
power system at a mine site, and then moved at the
end of the mine operations to another site.
In some cases there is an opportunity to develop a
renewable energy project for a mine located close to a
remote community. As the mine operation stops,
renewable electricity can be used for the communities
in the vicinity.
Technology maturity – While grid connected wind and
solar PV are mature technologies, there are few
examples of large off-grid projects. First-of-a-kind
projects are generally considered high risk, which
increases the costs of financing and can make
businesses require evidence of large returns before
they are prepared to proceed.
Although there are limited examples in Australia’s
mining sector, successful examples of remote towns
being powered by solar or wind hybrid systems do exist
and a few off-grid case studies are provided throughout
this paper. Internationally more demonstrated
examples are available (including specifically in the
mining sector).
ARENA’s RAR program will likely assist in developing a
track record of successful off-grid renewable energy
projects. This is fundamental to give the mining
industry confidence that off-grid solar or wind can be
integrated to a diesel or gas system in a reliable way.
These projects should follow detailed engineering
studies to minimise the risk of failure, which could
cause long-lasting reputation damage to the industry.
Projects with a high risk profile (such as mining
projects) should start with lower a penetration of
renewable energy, while a few show-case projects with
high penetration of renewable energy could be
developed in remote communities that present a lower
risk profile.
Labour costs – The remote location of many mines
means that labour costs are typically very high. The
proximity of the mining industry itself also tends to
increase the cost of labour.
The increased labour costs in remote locations should
be taken into account. This is particularly important
during the construction phase when skilled labour
requirements are highest. Ongoing operations and
maintenance costs can be maintained at a low level
with remote monitoring. An on-site presence is likely to
be required for security and basic cleaning, but skilled
maintenance can be called upon as required.
It is very important that the systems deployed on
mining sites are designed to be robust and reliable to
minimise maintenance cost.
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Cyclone risk – Some areas, such as coastal sites in
the Pilbara, are vulnerable to extreme cyclonic winds
and rain.
In these areas, wind and PV installations must be
designed to withstand cyclone conditions. The
mounting and anchoring can be designed to withstand
greater loads, or it may prove feasible to install
adjustable solar systems or wind turbines that are
designed to be laid flat when a cyclone is anticipated at
the site. This is the case in Coral Bay (see section
7.1.4). For larger sites, cyclone-proof wind turbines are
available in the market.
These systems are more expensive but many are still
likely to be competitive with diesel costs. These
projects may also seek funding from ARENA’s RAR
programs.
Competition from gas – Gas generation is
substantially cheaper than diesel generation and so it
presents a far less attractive business case for
integrating renewables. In particular, where gas is
available from a pipeline; renewable energy cannot
compete against gas-fired power.
Gas prices are subject to fluctuation and renewable
energy can be seen as a hedge against the risk of high
gas prices.
In remote locations, where there is no accessible gas
pipeline, Compressed Natural Gas (CNG), Liquefied
Natural Gas (LNG) or even gas pipeline expansions
are regularly considered in parallel with renewable
energy options. The preferred option depends on a
number of site specific factors.
Renewable energy’s environmental benefits outweigh
those of gas.
6.3
Some mines use trucked gas, which can be very
expensive depending on the distance it is trucked,
opening an opportunity for renewable hybridisation.
Independent Power Producers
In the off-grid industrial sector, it is commonplace to procure electricity from Independent Power Producers (IPPs).
IPPs build, own and operate power plants on behalf of an energy user. The project is typically reliant on the terms
and conditions of a Power Purchase Agreement (PPA), which guarantees a revenue stream for the IPP. Payment
to the IPP might be based on a combination of one or more of fuel consumption, electricity output, fixed charges
and take-or-pay arrangements.
The off-grid generation portfolios of two major IPPs operating in the off-grid market of Australia are provided
below.
6.3.1
Energy Development Ltd
Energy Developments Ltd (EDL) develops, owns and operates electricity generation facilities in remote off-grid
communities and for remote off-grid industrial users throughout Australia. Generated electricity is either sold to
retailers such as Horizon Power, Ergon Energy or Power and Water Corporation or directly to industrial users
(e.g. mines). Energy Developments Ltd owns 743 MW of generating assets in Australia including a number of offgrid energy generation facilities located in Queensland, Northern Territory, Western Australia and South Australia.
These generation facilities are either LNG, gas or diesel fuelled and have generation capacities of 1 MW to
40 MW each.
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Table 20
EDL’s remote power
stations
Power Station
Installed
Capacity
(MW)
WKPP
70
Cannington
40
Pine Creek
35
Sunrise Dam
28
McArthur River
24
Wodgina
14
Darlot
12
Other
57
Total
280
Figure 20
Energy Developments Ltd power stations
Source: (EDL, 2012)
Source: (EDL, 2012)
6.3.2
Pacific Energy
Pacific Energy acquired Kalgoorlie Power Systems (KPS) in May 2009. Pacific Energy owns and maintains a
portfolio of approximately 210MW of gas and diesel fuelled electricity generation, supplying power to Australia’s
resource sector in Western Australia, Northern Territory and South Australia and 6MW of hydro generation
located in Victoria supplying the National Electricity Market. Figure 21 describes some locations of Pacific Power’s
portfolio, which is predominantly for off-grid industrial electricity users.
Figure 21
Pacific Energy power generation facilities
Source: (Pacific Energy, 2014)
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6.4
Off-grid industrial case studies
An overview of renewable energy projects that have been recently developed in the off-grid industrial sector are
described in Table 21.
Table 21
Case studies in the mining sector
66kW hybrid system for BHP
Galaxy Resources Mount Cattlin mine
BHP installed a 66kW hybrid diesel/battery storage/
photovoltaic system to supply electricity to a remote
communications tower critical for mining operations.
Commissioned in November 2012, it is designed to
provide 100 per cent renewable energy for 5 days
without requiring the diesel generators to run.
Galaxy Resources have installed 14 dual tracking solar
panels and two wind turbines at Mt Cattlin lithium mine
and processing plant. The plant produces 226MWh per
year of renewable energy and supplements the 5MW
diesel generator (approximately one sixth of the total
load). (Galaxy Resources, 2013)
Rio Tinto Weipa bauxite mine
6.7MW of solar power and energy storage will be
developed on the Weipa bauxite mine in Queensland. It
is expected to reduce daytime diesel demand from the
mine’s 26MW diesel generator by up to 20 per cent.
ARENA has committed $10.3 million to the two phases
of the project.
6.5
Other off-grid Industrial applications
Other off-grid industrial applications for renewables cover a wide range of applications including:
Table 22
Off-grid industrial opportunities
Category
Example
Opportunity
Off-grid
Industry
Meat processing
facilities
Off-grid meat processing facilities use over 66 per cent of their energy through
the operation of processing equipment, boiler losses and refrigeration (NFEE,
2004). The thermal loads provide an opportunity for implementing solar
thermal and cold stores provide an opportunity for demand management.
Data commissioned by BREE in 2013 indicates there is an estimated 62MW
of installed capacity supplying approximately 196GWh to the off-grid
agricultural sector, see table below.
Estimated Agricultural
Electricity Demand
DKIS
Communications
Capacity
17
5.4
Rest of Northern Territory
68.1
21.6
Queensland
69.8
22.1
Western Australia
35.7
11.3
South Australia
2.8
0.9
New South Wales
2.3
0.7
195.7
62
Total
Off-grid
Infrastructure
Consumption GWh
MW
Powering mobile and IT communications infrastructure is particularly
challenging in remote areas with limited mains grid power. Often these off-grid
mobile towers are powered by diesel generators. There is a great potential to
increase the use of renewable energy in this sector, which accounted for only
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Category
Example
Opportunity
0.11 per cent in 2010 (Green Telecom Networks, 2010).
Desalination
Most desalination plants consume a large amount of energy, therefore finding
methods of using renewable energy to power the desalination process is
desirable. Solar collectors or wind turbines can be used to provide heat or
electrical energy required to operate a standard reverse osmosis, electrodialysis, or distillation desalination plant.
Renewable energy systems can easily be oversized and paired with water
storage (which is cheaper than energy storage) to facilitate 100% renewable
energy, with diesel operating as a backup only. This works by powering the
desalination plant with renewable power (only) such that it provides sufficient
water despite intermittency issues. The water tank acts as a buffer between
the intermittent production of water and the demand for water.
Pumping and
Irrigation
There are more than 10,000 solar powered surface and bore water pumps in
use around the world today (TRL Solar, 2013). Solar is already widely used on
farms and outback stations in Australia to supply bore and surface sourced
water to livestock. In remote regions there is an opportunity to further adapt
renewables for pumping water from wells and rivers to communities for
domestic consumption and irrigation of crops. Once a very expensive
technology, prices have dropped in recent years.
A typical solar powered pumping system consists of a solar panel array that
powers an electric motor, which powers a bore or surface pump. The water is
often pumped from the ground or stream into a storage tank that provides a
gravity feed, so energy storage is not needed for these systems. PV powered
pumping systems are a cost-effective alternative to agricultural wind turbines
for remote area water supply. (Energy Matters)
Tourism
6.5.1
Resorts, Hotels,
Islands
Interest in Renewable Energy Technology is high within the tourism sector;
primarily for cost savings, ethical reasons and social responsibility as opposed
to benchmarking, marketing or as a potentially more reliable energy source.
Non-Mining Industrial renewable energy opportunities
Square Kilometre Array
The Square Kilometre Array (SKA) project is a global project to build the world’s largest radio telescope in Mileura
(WA). The project is led by the SKA Organisation and involves a number of organisations from different countries
including the CSIRO.
In December 2011 Horizon Power received $15.5 million in funding to construct a 1MW power station to support
the Australian Square Kilometre Array Pathfinder Project (ASKAP), a pilot project for the SKA project. The ASKAP
represents approximately 1 per cent of SKA project development. The generation system will be a renewable
hybrid system and will be designed to be “radio-quiet”.
Table 23
Key stakeholders and considerations of the Square Kilometre Array
Key Stakeholders
Considerations
Horizon Power
Technically challenging project. The system must be
“radio-quiet” and extremely reliable
CSIRO
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Algae project in the Pilbara
As part of its vision to create an attractive region, the Pilbara Cities Office is encouraging industry diversification
across the region. In 2012, the Office commissioned a study to assess the opportunities for the development of an
algae-based industry in the Pilbara. Algae can be used to produce a number of renewable, carbon neutral biofuels
including biodiesel, methane, ethanol and jet fuel. The study highlights that the Pilbara’s climate and access to
seawater and carbon dioxide make it an ideal region for the development of an algae industry. (WorleyParsons,
2012)
There is already a developing algae industry in the region and a growing interest in these technologies. Recent
projects include Aurora Algae’s demonstration project in Karratha and their commercial scale farm in the Maitland
area (in development). Sapphire Energy and Murdoch University research funded by Rio Tinto are also involved
in this new industry.
Table 24
Key stakeholders and considerations of Pilbara algae project
Key Stakeholders
Considerations
Rio Tinto and Murdoch University
Industry relatively immature
Aurora Algae
Little skilled workforce in this space
Sapphire Energy
Development Approval difficult to obtain
Pilbara Cities
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7.0
Off-grid Communities Market
Over two-thirds of the total Australian population reside in major cities in comparison to just 2.3 per cent (half a
million people) who live in remote areas of Australia (ABS, 2013). The remote population has experienced a
modest 8.25 per cent growth rate over the ten years to 2011, with some regions (Victoria, NSW and Tasmania)
experiencing negative growth over this period. The off-grid community energy sector is currently supplied primarily
through state and territory owned NSP’s such as Horizon Power (WA), Ergon Energy (QLD) and Power Water
Corporation (NT).
This paper focuses on Western Australia, Queensland, Northern Territory and South Australia which together
make up approximately 80 per cent of the Australian remote population and offer the greatest potential
opportunity for off-grid and fringe-of-grid renewable energy. This is highlighted in Figure 22.
Figure 22
Remote and very remote populations in each State (as per the Australian Statistical Geography Standard categories)
Source: (ABS, 2013)
The off-grid community energy market is a combination of islanded micro grid systems supporting communities
and mining towns. In off-grid community markets, States and Territories pay a Community Service Obligation
(CSO) to energy suppliers to subsidise the cost of energy to consumers. Electricity supply is considered an
essential service and the National Framework for Energy Services Obligations is aimed at providing equity in
electricity pricing across Australia (MCE, 2008). The actual costs of providing electricity services to customers in
remote and regional areas is substantially higher than providing the same services in metropolitan areas due to
higher fuel costs, lower economies of scale and lower customer density. All regional and remote customers in a
particular class (i.e. residential and small business) receive the benefits of the CSO. The CSO is not means tested
and varies across the states and territories. They include a combination of concessional tariffs, grants and
rebates.
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Table 25
Approximate* Community Service Obligation payments to selected utilities for regulation of remote electricity users
Utility
CSO Payment (2012-13)
Western Australia (Horizon Power)
$154 million
Ergon (Queensland)
$620 million
Power and Water Corporation (Territory)
$76 million
*figures may include contribution to water and sewage services
Source: (Horizon Power, 2013), (Queensland Treasury, 2013), (Power and Water Corporation, 2013)
Growth in Mining Towns
Over the 12 years up to 2012 employment in the mining industry has tripled in Australia, peaking at 276,300
people employed which has consequentially driven strong population growth in mining towns where 'fly-in, fly-out'
and 'drive-in, drive-out' workers reside (ABS, 2013).
Figure 23
The ten strongest growth mining cities
Source: (ABS, 2013)
Apart from Weipa in far North Queensland and Roxby Downs in South Australia, the 10 mining towns with the
strongest growth between 2006 and 2011 are all located in either the Bowen Basin in Central-eastern Queensland
or in the Pilbara region (see Figure 23). These mining towns have experienced a population growth between 18
per cent and over 51 per cent over the five years to 2011 (ABS, 2013). The large influx of people to these once
rural towns is creating a need for new infrastructure. Most mining towns are investing heavily to improve their
supply of affordable and accessible essential services such as electricity and water.
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7.1
Western Australia
In recent years Western Australia has experienced an unprecedented population growth driven by a rapid
development of the mining industry. WA's population increased by 24 per cent to 2.35 million in the ten years to
2011 and is expected to double in the next 30 to 40 years (ABS, 2011). The Western Australian Government and
private companies are supporting this growth with multi-billion dollar infrastructure projects and services.
With 1.83 million people, the population of greater Perth represents 78 per cent of the state’s population and
experienced a 26 per cent growth over the ten years to 2011. The Pilbara recorded a 59 per cent population
growth (23,300 people) over the same period, the state’s fastest population increase.
Figure 24
Population change in WA between 2001 and 2011
Source: (ABS, 2011)
7.1.1
Remote communities
Horizon Power supplies electricity to 36 isolated communities through Western Australia (see Figure 26 in section
7.1.2). As highlighted in Figure 25 below, diesel and gas are the primary energy sources.
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Figure 25
Electricity supply in Horizon Power remote communities (in GWh)
Source: AECOM based on horizon power annual report and website
Seven out of the nine remote grids supplying a load above 10GWh are partly or fully supplied by gas-fired plants.
The majority of the smaller remote loads involve diesel generators.
Table 26
List of remote communities serviced by Horizon Power
Communities
Electricity consumption (MWh)
Current Energy source
Ardyaloon
1,697
Diesel
Beagle Bay
1,578
Diesel
Bidyadanga
2,708
Diesel
Broome
130,238
Gas
Camballin/ Looma
2,691
Diesel
Carnarvon
49,044
Gas
Coral Bay
3,079
Diesel/Wind
Cue
2,015
Diesel
Denham
5,528
Diesel/Wind
Derby
36,196
Diesel/Gas
Djarindjin/ Lombadina
1,613
Diesel
Esperance
70,257
Gas/Wind
Exmouth
24,992
Diesel/Wind
Fitzroy Crossing
14,100
Diesel/Gas
Gascoyne Junction
631
Diesel
Halls Creek
11,221
Diesel/Gas
Hopetoun
5,853
Diesel/Wind
Kununurra
63,764
Diesel/Hydro
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Communities
Electricity consumption (MWh)
Current Energy source
Kalumburu
540
Diesel
Lake Argyle
222
Hydro
Laverton
4,598
Diesel
Leonora
10,881
Gas
Marble Bar
2,365
Diesel/Solar
Meekatharra
7,402
Diesel
706
Diesel
Menzies
Mount Magnet
4,103
Gas
Norseman
4,148
Diesel
Nullagine
1,171
Diesel/Solar
Onslow
8,159
Diesel/Gas
Sandstone
709
Diesel
Warmun
2,927
Diesel
Wiluna
2,851
Diesel
Wyndham
9,080
Diesel/Hydro
Yalgoo
943
Diesel
Source: AECOM; (Horizon Power, 2012-13)
7.1.2
Key stakeholders
Horizon Power is Western Australia's primary regional and remote electricity provider servicing both communities
and major industrial users. Horizon Power manages two interconnected electricity networks, the North West
Interconnected System (NWIS) in the Pilbara and the East Kimberly Interconnected System, as well as 36 noninterconnected or islanded systems in regional towns and remote communities.
Horizon Power services the biggest area with the least amount of customers in the world with just one customer
for 53.5 square kilometres.
Horizon Power’s generation portfolio is predominantly gas and diesel-fired, however wind, solar and hydro
generation facilities also feature. Horizon Power has recently commissioned two solar diesel hybrid power
stations in the remote Western Australian communities of Marble Bar and Nullagine.
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Figure 26
Horizon Power’s power stations
Source: Horizon Power website
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Verve Energy (now Synergy) is a major supplier of electricity within the SWIS, however they also own and
operate a number of remote off-grid generation facilities in Western Australia including renewable energy assets
integrated with Horizon Power diesel and gas generation systems at Hopetoun, Coral Bay, Denham, Esperance
and Bremer Bay.
The Department of Aboriginal Affairs (DAA) of Western Australia is responsible for advising Government on the
adequacy, implementation and coordination of services to Aboriginal people in Western Australia. Amongst other
tasks, the DAA works with Aboriginal Australians to improve the delivery of services in remote communities.
7.1.3
Renewable energy opportunities
Pilbara Cities
The Pilbara is located between the Kimberley and the Tropic of Capricorn. It is home to approximately 60,000
people over approximately 508,000 square kilometres. The Pilbara region is rich in minerals and hydrocarbons,
becoming an important mining and export region of Australia. The Pilbara population has experienced strong
growth over the past few years, which is expected to continue, needing infrastructure development, including in
the power sector.
In 2013 there are $100 billion worth of committed projects in the Pilbara and over 7,000 new dwellings required by
2015.
Some of the Pilbara’s fastest growing centres including Karratha and Port Hedland, which are envisioned as cities
of 50,000 people each by 2035, Newman with a forecast population of 15,000 people and Tom Price and Onslow.
Since 2009 approximately $1.2billion in State Government Royalties for Regions funding has been committed to
transform the Pilbara through the Pilbara Cities program. Pilbara Cities was established in April 2010 to help
develop the necessary infrastructures associated with significant growth in the region. Pilbara Cities Office (PCO)
was created to ensure the royalties are used in line with the government, industry, business and community
objectives.
A number of projects are already in development in Karratha, Port Headland, Onslow and Newman.
Additional generation capacity will be required in the NWIS as well as in some regional centres including Onslow
and Newman to meet the region’s growing demand.
A few projects recently developed or in development include the following:
-
BHP building a 178 MW gas plant in Newman
-
Rio Tinto is planning for 120 MW open cycle gas turbines
-
CITIC Pacific recently built a 450 MW combined cycle gas-fired power station
-
Onslow Power Station – Chevron is to build a new gas power station in Onslow to meet the demand from
the forecast population growth. A 1 MW generator was installed at the end of 2013 and Horizon and
Chevron are working together towards a plan of installing 9MW by 2016 (Horizon Power, 2012).
-
The 18MW Mungullah gas power station was completed at the end of 2013 near Carnarvon
-
In South Headland, a new 67MW power station will provide power until a new long-term 110MW power
station is completed, which is planned for 2017. (Horizon Power, 2014)
Horizon Power is forecasting the generation in the Piblara to grow substantially over the coming decade. For
example, demand is expected to triple in Onslow by 2016-17 as a result of Chevron’s Wheatstone project. To
meet the short term growing demand, the utility is planning to build new power stations and to secure additional
capacity through the renewal of power purchase agreement (PPA) such as the PPA with Alinta in Port Hedland
(Horizon Power, 2012). In parallel, Horizon Power is working with the State Government to define the best
approach to optimised power development in the Pilbara in the long term.
In its 2009 submission to the Energy White Paper, Horizon Power stated: “The Pilbara, Mid-West, and even
the south coast of Western Australia could become renewable energy centres. The Pilbara is unique in that it
is close to wind, wave and geothermal resources and to 90 per cent of Australia’s known oil and gas
resources, has coastal access that could facilitate large-scale combined cycle power generation and,
importantly, has a world-class solar resource.” (Horizon Power, 2009)
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There are significant opportunities to collaborate with Pilbara Cities, Horizon Power and the mining sector to
integrate renewable energy into the short and long term strategy of the region. The renewable energy project
development would likely consist in hybridisation of new or existing generation systems in the Pilbara with wind or
solar.
Key challenges renewable energy projects in the Pilbara Cities must overcome include the extreme climate and
regulatory environment. The Pilbara’s climate is both arid and tropical, which experiences high temperatures and
low irregular rainfall following the summer cyclones. Cyclones and flooding are major hazards in the Pilbara with
periods of torrential rainfall between November and May and approximately seven cyclones every ten years.
During the summer months, maximum temperatures exceed 32 °C almost every day, and temperatures in excess
of 45 °C are not uncommon. Land owner and environmental approvals may be challenging and should be
considered early in the project
Carnarvon
The population growth in Carnarvon is driving increasing electricity demand. Horizon Power recently built the $73
million Mungullah Power Station (18 MW) to replace the existing power station and meet the long term electricity
needs of the community and businesses.
The power station is comprised of five diesel generators and five gas generators. The gas is supplied via the
Dampier to Bunbury Gas Pipeline Carnarvon Lateral and has become the primary fuel source due to its cheaper
price.
There may be an opportunity to integrate up to 3.6MW of renewables at Carnarvon (based on a 20 per cent
penetration of renewable energy in the 18MW power station), however the cheaper gas-fired generation may
makes this location less attractive than similar diesel-powered communities.
Kimberley Indigenous communities
A number of Kimberley Indigenous communities, serviced by Horizon Power or other regional service providers,
need important upgrades of their power supply systems.
Every year a few communities benefit from the Horizon Power Aboriginal and Remote Community Power Station
Project (ARCPSP) funded by the Australian and State Governments. The program is designed to improve the
power supply to remote Indigenous communities.
Two recent projects, the Kalumburu and Yungngora power systems, were funded under ARCPSP via Horizon
Power. In 2012, the utility upgraded the electrical networks of Yungngora and Kalumburu and new diesel power
stations were completed at Kalumburu and Yungngora in 2013 (Horizon Power, 2012).
The Remote Area Essential Service Program is also available to assist in the improvement of power supply for
remote communities. Kimberley Regional Service Providers (discussed further in section 7.5.2) have been
involved in a number of projects under their Remote Area Essential Service Program contract.
The large remoteness and dispersed nature of the communities presents a number of logistical and scale
challenges for renewables deployment. The cost of construction and maintenance is also exceptionally high in
remote areas. As such the hybrid the systems deployed must be robust and reliable.
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7.1.4
Table 27
Case Studies
Case studies in Western Australia
Marble Bar
The Marble Bar community is located in the Pilbara in Western Australia. The town’s power system is managed by
Horizon Power, which operates a hybrid system comprised of a 1.28MW diesel plant (four 320 kW units) and a
302 kW solar tracking system.
The total integrated system (including the diesel units) was commissioned in May 2010 at a capital cost of $16
million. The facility was awarded a $4.9 capital grant under the Federal Government Remote Renewable Power
Generation Program (this grant was shared with the Nullagine project described in the following section).
The town sources 30 per cent of energy from the solar units, with an instantaneous peak of up to 92 per cent from
solar. 65 per cent of daytime energy is supplied by solar (Horizon Power, 2012).
A single 500kW fly-wheel energy storage system is included in the system to manage power quality and system
stability.
The system enabled the average duration of power outages to be reduced from 38 minutes in 2009-10 to 8
minutes in 2010-11 (Horizon Power, 2012).
Nullagine
The Nullagine community is located in Western Australia, and features a peak demand of 0.4MW. The power
supply is managed by Horizon Power. They operate 0.96MW of diesel capacity supplemented by 203kW of solar
capacity (900 panels). The solar system supplies 30 per cent to 40 per cent of the town’s energy demand.
The total integrated system (including the diesel units) cost $14 million to install in October 2010. The facility
shared with the Marble Bar project a $4.9 capital grant from the Federal Government.
As with the Marble Bar system, the solar-diesel hybrid installed at Nullagine has operated reliably and enabled a
reduction in the average interruption time 110 minutes in 2009-10 to no interruption in 2010/11 (Horizon Power,
2012).
Coral Bay
The Coral Bay community is located in the Pilbara, in Western Australia. The community features a peak demand
of 600kW, and a minimum demand of 200kW (ABB, 2012).
The town’s electricity system is managed by Horizon Energy. It comprises 7 x 320kW low load diesel generators
integrated with Verve Energy (now Synergy) renewable assets including three 275 kW wind turbines and a 500kW
inverter coupled flywheel (Ecogeneration, 2008).
The total integrated system (including the diesel units) cost $12 million to install in 2007. The facility was
supported by a 50 per cent capital grant under the Federal Government’s Remote Renewable Power Generation
Program for the renewable component (Evans & Peck, 2011).
The town sources 45 per cent of energy from the wind turbines. Wind generation routinely exceeds 90 per cent of
the town’s requirements.
The wind turbines are designed to be tilted down in the event of extreme wind events, such as an approaching
cyclone. The low load diesel generators can be run for sustained periods at loads as low as 5 per cent and provide
voltage and frequency regulation.
The system is control by a renewable micro-grid controller.
The wind energy input saves approximately 500kL of diesel per year, which formed the basis for the project
business case. In addition, the flywheel energy storage reduced the need to run an extra diesel unit for spinning
reserve, allowing additional maintenance cost savings.
Leinster mining township
BHP-Billiton Nickel West division installed solar PV to the rooftops of the Leinster township which supports the
nickel mine. 195 1.5kWp CIS thin film technology solar panels were installed with full web-based remote power
system monitoring in 2011 for a capex of $1.5 million.
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7.2
Northern Territory
With a population of approximately 235,000 people (ABS, 2012), the Northern Territory represents 1 per cent of
Australia’s population and has the lowest population density of any state or territory. Approximately 56 per cent of
the population lives in Darwin and another quarter live in five regional centres: Alice Springs, Katherine, Tennant
Creek, Jabiru and Nhulunbuy. The remaining population lives in remote communities.
Between 2001 and 2011, the Northern Territory experienced the third fastest population growth after Western
Australian and Queensland (ABS, 2011). Figure 27 geographically depicts the population change over the ten
years to 2011. Greater Darwin experienced the largest population increase, while the remote north areas of the
Territory recorded the fastest population growth.
Approximately 30 per cent of the Northern Territory’s people are indigenous, compared with 2.5 per cent
nationally. Over 550 Indigenous communities and outstations are not connected to the main grids.
Figure 27
Population change in the Northern territory between 2001 and 2011
Source: (ABS, 2011)
7.2.1
Territory growth towns and remote communities
Power and Water Corporation (PWC) supplies electricity to the Territory’s major interconnected network as well
as to six main communities (refer to section 5.2). PWC owns an aggregated generation capacity of 559MW (with
an additional 57MW under independent Power Purchase agreements) and supplied approximately 2,000 GWh of
electricity in 2012-13.
Indigenous Essential Services (IES; a subsidiary of PWC) supplies electricity to 20 Territory Growth Towns
(TGTs) and 52 remote indigenous communities. The supply of electricity to these remote communities is very
costly and largely subsidised by the Northern Territory Government.
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Figure 28
Energy sources used by IES to supply electricity to Indigenous communities
Source: (Green Energy Task Force, 2011)
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Territory Growth Towns
Between 2006 and 2011, the 20 Territory Growth Towns experienced an 11 per cent Indigenous population
growth, approximately double the growth rate of the Indigenous population of the Northern Territory (NT). These
Territory Growth Towns have been identified by the Northern Territory and Australian Governments a as a target
for investment to enhance services, infrastructure and facilities.
As highlighted in the table below, the majority of the Territory Growth Towns are supplied electricity from diesel
generators. Fourteen towns are using solely diesel generators, which have together produced over 57,600 MWh
in 2011. To put this figure into perspective, approximately 35MW of solar PV is necessary to produce the
equivalent amount of electricity. In reality, replacing all diesel systems with solar would likely require a larger solar
capacity and very expensive energy storage.
Table 28
Territory Growth Town electricity supply status (2011)
Territory Growth Towns
2011 electricity consumption (MWh)
Current Energy source
Serviced by PWC
Borroloola
4,190
Diesel
Elliott
1,710
Gas
Ali Curung
1,620
Gas
Angurugu
3,990
BHP/GEMCO mine
Deguragu-
990
Galiwinku
6,140
Diesel
Gapuwiyak
2,630
Diesel
Gunbalanya (Oenpelli)
4,320
Diesel
Hermannsburg
3,020
Diesel/ solar/ LPG
Kalkarindji
2,320
Diesel
Lajamanu
2,900
Diesel/ solar
Maningrida
8,310
Diesel
Milingimbi
3,330
Diesel
Nguiu
6,200
Diesel
Ngukurr
4,100
Diesel
Numbulwar
2,760
Diesel
Papunya
1,570
Diesel
Ramingining
2,970
Diesel
Umbakumba
2,080
Diesel
Wadeye
6,700
Diesel
Yirrkala
3,300
Rio Tinto Power station
Yuendumu
3,400
Diesel/ solar
Serviced by IES
Source: (Green Energy Task Force, 2011)
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7.2.2
Key stakeholders
Power and Water Corporation (PWC) provides electricity, water and wastewater services to customers across
the Territory. PWC has a total generation capacity of 615 MW (558MW Generation owned with 57MW under
power purchase agreements with independent power producers), most of which is connected to the DarwinKatherine interconnected system. PWC also own and operate a number of smaller remote off-grid gas or dieselfired power stations.
Power and Water Corporation’s wholly owned subsidiary Indigenous Essential Services (IES) delivers
electricity, water and wastewater services to remote Indigenous communities. IES owns and operates 200
generators accross 52 diesel-fired power stations totalling 73 MW installed capacity and over 1,000km of
transmission lines. IES are exploring options to offset high diesel fuel, transportation and storage costs including
the use of solar and wind generation to augment diesel generators. IES uses solar/diesel hybrid generation in
eight mini-grids that power eleven remote indigenous communities.
The Centre for Appropriate Technology (CAT) is a non-governmental organisation that works with remote
communities to secure sustainable livelihoods through access to appropriate technology. CAT was established in
1980 and is incorporated under the Northern Territory Associations Act. CAT is governed by an Indigenous board
and established the Bushlight program in 2002 to increase access to renewable energy in small Indigenous
communities. Bushlight has installed over 140 stand-alone solar and solar-diesel systems in remote communities
and they have over 260 systems on their repair and maintenance program.
The NT Cattlemen's Association (NTCA) is the peak cattle industry body in the Northern Territory and is actively
involved in supporting the deployment of renewable energy on the Territory’s cattle stations.
7.2.3
Renewable energy opportunities
Indigenous Essential Services communities
The vast majority of Territory Growth Towns (TGTs) and the 52 remote communities served by IES use diesel
generation as their primary electricity source. Although individual power demand of each town is small, the
aggregated capacity represents a reasonable opportunity to use renewable energy (likely solar energy) to offset
part of the diesel consumption.
In 2012, approximately 30 million litres of diesel was transported to remote power stations (PWC, 2012). IES is
exploring renewable energy options to offset diesel fuel, transportation and storage costs. Six remote indigenous
communities already have solar augmenting diesel generation with a total installed capacity of 800 kW with further
sites in planning stages (Indigenous Essential Services, 2011).
There is an opportunity to work with PWC or IES to develop renewable energy projects for the remote
communities they supply.
IES has an installed diesel capacity is approximately 74MW and the demand was 110GWh in 2011. In late 2009,
the Green Energy Taskforce developed a roadmap for the development of renewable energy in the Northern
Territory, which recommended the initial development of 10MW of solar power over three to four years to offset
diesel in remote communities. In a second stage, the roadmap suggested a 100 per cent substitution of diesel
generation with renewable energy and low emission fuel.
The large number of small, remote and dispersed communities managed by IES presents a number of logistical
and scale challenges for renewables deployment. The cost of construction and maintenance is also exceptionally
high in remote areas. As such the hybrid the systems must be robust and reliable.
7.3
Queensland
With 4.4 million people, Queensland’s population grew by 23 per cent between 2001 and 2011. The majority of
the population is concentrated in South East Queensland, which experienced significant growth over this period.
The population increase in far North Queensland and Mackay was primarily driven by the development of the
mining industry in these areas. Except for the Far North Queensland region, most of regional Queensland
experienced a decrease in population over the ten years to 2011.
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Figure 29
Population change in Queensland between 2001 and 2011
Source: (ABS, 2011)
7.3.1
Remote communities
Ergon Energy designs, installs, owns and operates power systems in 33 remote communities across the state of
Queensland (see section 7.3). When developing a remote energy project, Ergon Energy is required to assess the
benefits and limitations of different types of power systems. Some of the key requirements for the design of the
remote station are that it must be designed as an unmanned, secure and reliable system. These remote off-grid
power stations range from 165 kW to 9.55 MW installed capacity. All of Ergon Energy’s remote power stations use
diesel as their primary fuel. As highlighted in Table 29, three of the power stations are augmented with renewable
energy supplies including geothermal at Birdsville, wind at Thursday Island and solar at Windorah.
Table 29
Ergon Energy community asset portfolio ( December 2012)
Number of systems by size (2011-12)
Diesel
30 - 100kW
100kW - 500kW
500kW - 1MW
1MW - 10MW
1
19
6
3
Hybrid (Diesel / Solar)
1 (Windorah)
1 (Doomadgee)*
Hybrid (Diesel / Wind)
1 (Thursday Island)
Hybrid (Diesel / Geothermal)
TOTAL
1 (Birdsville)
1
20
* Doomadgee Solar Farm is currently under construction and will be commissioned in 2013
Source: Ergon Energy
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7.3.2
Key stakeholders
Ergon Energy is one of Queensland’s two primary electricity providers operating within the NEM (the other being
Energex). Ergon Energy also owns and operates 33 remote off-grid power stations throughout western
Queensland, the Gulf of Carpentaria, Cape York, Torres Strait, Palm and Mornington Islands. These remote offgrid power stations range from 165 kW to 9.55 MW installed capacity. All of Ergon Energy’s remote power
stations use diesel fuel. Three of the power stations are augmented with renewable energy supplies including
geothermal at Birdsville, wind at Thursday Island and solar at Windorah.
Figure 30
Ergon Energy Network
Source: (Ergon Energy, 2013)
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7.3.3
Renewable Energy opportunities
Ergon Energy remote communities
There is an opportunity to work with Ergon Energy to develop renewable energy projects to offset diesel
consumption in remote communities. According to Ergon Energy, small penetrations of renewable energy are
already commercially viable. Ergon Energy already has a few operating renewable energy projects (described in
section 7.3.4) and is currently assessing wind, solar and geothermal opportunities in a number of locations:
Birdsville New Geothermal Power Station - Ergon Energy is currently investigating options to increase the
electricity production from the geothermal resource at Birdsville. It is expected that a significant part of the cost will
be in the integration of geothermal system to the existing diesel system.
Thursday Island Upgrade Wind Turbines – The wind system on Thursday Island is at the end of its life. Ergon
Energy has initiated a feasibility study to assess the viability of increasing the wind farm capacity.
Doomadgee solar farm stage II – Ergon Energy is assessing the option to increase the penetration of renewable
energy in Doomadgee. The system would require integration and stability devices resulting in the need for
additional funding to make it commercially viable.
Moa Island and Badu Island wind projects – Ergon Energy is investigating the possibility to install wind
systems on the two islands, in the Torres Straits. The projects are at an early stage of their development and no
wind monitoring equipment has been installed to date.
Gununa, Mornington Island and Bamaga Solar Farms – Ergon Energy is investigating the possibility to install
solar systems in Gununa and Bamaga and on Mornington Island. The projects are at an early development stage.
Fringe-of-grid systems – Queensland has an extensive fringe-of-grid area with low population density and long
distribution lines with large loss factors and expensive augmentation costs. There is a significant technical benefit
to the fringe-of-grid systems if appropriate funding and revenue streams can be found.
The small scale, remoteness and dispersed nature of the opportunities presents a number of logistical and scale
challenges for renewables deployment. The cost of construction and maintenance is also exceptionally high in
remote areas. As such the hybrid the systems must be robust and reliable.
7.3.4
Table 30
Case studies
Case studies of Ergon Energy remote communities
Windorah Solar Farm
Doomadgee Solar Farm
The Windorah solar farm was installed in 2009. It
consists of five 26kW solar concentrated dishes
integrated to the diesel power station, which has been
configured to run at low loads enabling up to 80 per
cent instantaneous penetration of renewable energy.
Battery storage is used to smooth the output of the
solar system. The solar system supplies 17 per cent of
Windorah's energy needs.
The 264kW Doomadgee solar farm is due to be
commissioned in early 2013 in Doomadgee (North
West Queensland).
The project is to displace 300 tons of greenhouse gas
emissions by reducing the consumption of diesel by up
to 100,000 litres per year (Ergon Energy, 2012).
“The solar farm will also help ensure reliable supply of
power during the wet season when vehicle access to
the community is cut off – sometimes for up to six
months – hampering diesel fuel deliveries.” (Ergon
Energy, 2012)
The project’s capital cost amounted to $4.6 million.
According to Ergon Energy, the solar plant should save
around 115,000 litres of diesel each year. It will have a
winter penetration of 50 per cent without storage and
provide 8 per cent of the total energy needs of
community.
Wind at work on Thursday Island
Ergon Energy's geothermal power station
Thursday Island has 4,000 residents and is not
connected to the NEM. Ergon Energy built a $2.5
million wind farm (450kW) integrated to the diesel
generation system of Thursday Island, in the Torres
Strait.
Ergon Energy’s geothermal project uses near-boiling
water from the 1.3km deep Great Artesian Basin.
The wind farm supplies 5 per cent to 10 per cent of the
The project is located in Birdsville, about 1,600km west
of Brisbane, on the edge of the Simpson Desert.
The project provides approximately 30 per cent of
Birdsville’s electricity needs and reduces diesel
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island's electricity needs and saves approximately
300,000 to 600,000 litres of diesel annually. (Ergon
Energy, 2012)
7.4
consumption by 130,000 litres a year.
South Australia
The South Australian population increased by 8.4 per cent to 1.64 million in the ten years to 2011.This was the
slowest growth of all states and territories and the large majority of this population growth occurred in the Adelaide
region.
Figure 31
Population change in SA between 2001 and 2011
Source: (ABS, 2011)
7.4.1
Remote communities
The South Australian Government supplies electricity to remote communities in South Australia
The Indigenous communities located in the north west of the state are home to approximately 1,000 people
spread over 210,000 square kilometres. The annual electricity consumption of these communities is no more than
10GWh and is supplied by three systems:
-
Anangu Pitjantjatjara Yankunytjatjara – 14 communities, supplied by a 3.3MW central power station in
Umuwa. The electricity is transported to the communities via a 400km 33kV line.
-
Aboriginal Lands Trust, which supplies Yalta
-
Maralinga Tjarutja, which supplies Oak Valley
Outside of Indigenous land, approximately 2,600 people live in 13 remote towns, which together consume
approximately 15 GWh annually. Ten of the towns are serviced by the South Australian Government, who owns
and operates diesel generators with a combined production of approximately 3GWh.
Independent owner-operators supply electricity to the three remaining communities, with electricity subsidies from
the government.
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-
Andamooka – 2-3GWh pa
-
Coober Pedy – 11-12GWh pa supplied by 4MW of diesel
-
Yunta – 2-3GWh pa
All small domestic customers have subsidised electricity and pay no more than 10 per cent above the on-grid
regulated standing contract tariff.
7.4.2
Key stakeholders
The South Australian Government runs the Remote Areas Energy Supplies Scheme (RAES), which supplies
electricity to 13 remote towns and a further 16 remote Aboriginal communities and homelands. RAES’ generation
facilities are stand-alone diesel and LPG generators with the exception of one which is a solar-diesel hybrid
system.
7.4.3
Renewable energy opportunities
South Australian Government remote communities
As in other states, there is an opportunity to deploy renewable energy to offset South Australian remote
community diesel usage. There is an opportunity to amalgamate small projects through the South Australian
government.
The size of the aggregated capacity would remain relatively modest but could enable considerable fuel savings.
Other diesel generation in South Australia
The Government of South Australia commissioned a study in October 2013 to map out all the diesel generators
above 100kW in the state. The intention was to size the potential market for renewable energy. The information
was gathered through a survey sent to a number of stakeholders. The information sought included capacity
installed, number of engines installed and age of the assets. This database will provide a better understanding of
the size of the market in South Australia and there are intentions to update the database in 2015.
Table 31 summarises the off-grid and mini-grid diesel generation systems in South Australia.
Table 31
Diesel generation systems in South Australia
Diesel
generation
system
Number of
Plant
Plant per
organisation
Average
Size of plant
Average
Plant Size
Range (kVA)
Average
Generators
per plant
Number of
generators
per plant
Off-grid
49
1.63
1,389
0.3 – 20,000
1.63
1–5
Mini-grid
53
1
797
16 – 4,000
2.53
1–8
The database can be found in the following link:
http://www.renewablessa.sa.gov.au/investor-information/diesel-generators-directory
The study also conducted economic modelling of different power system configurations including:
-
fuel-saving PV: where the solar is sized to provide 30 to 35% of the minimum midday demand and
integrated with a continuously operating diesel plant
-
primary PV: PV-battery-diesel system where the solar is sized to meet most of the total load during the day
and the battery bank meeting the load during the night. The diesel generator is back-up power supply with
around 10% contribution to annual load.
The conservative results based on a set of assumptions indicated that:
-
for loads above 700kWh per day, the fuel-saving PV systems had the lowest lifecycle costs
-
for loads up to 350kWh per day, the primary PV system had the lowest lifecycle costs
7.5
Independent remote networks
A number of community systems are ran independently from the main state Network Service Providers. Examples
of these communities include: some remote islands that are managed by an independent board, outstations and
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homelands that are typically run by the community itself and some independent remote communities or groups of
communities. These are presented in further details in the following sections.
7.5.1
Islands
Australia has more than 8,000 islands ranging from the tropics to parts of Antarctica.
Diesel based power generation is generally the prime power supply to islands, leaving them vulnerable to volatile
oil prices, expensive transportation costs and the effects of fossil fuels on the local environment (including spill
risk). Many islands’ economics rely heavily on tourism, and expensive electricity decreases the affordability of the
island as a destination as the high electricity costs filter through to higher service costs.
The benefits of implementing renewables can include:
-
reducing energy costs and increasing profitability
-
attracting eco-friendly tourists willing to pay a premium for sustainable tourism experiences
-
reducing air and water pollution
-
increasing employment opportunities for the installation, operation and maintenance of renewable systems.
However some challenges unique to islands should be considered, such as:
-
the island’s long term vulnerability to climate change including sea-level rise and greater frequency of
extreme weather events
-
land value
-
aesthetic impacts.
Case studies
Some flagship case studies demonstrating the integration of renewables on islands are described in Table 32
below. A number of islands are and have investigated the use of renewables including King Island, Lord Howe
Island, Flinders Island and Rottnest Island.
This growing knowledge and experience in integrating renewables on Australian islands has potential to be
applied on South Pacific islands, where a number of aid programs are focusing support on transitioning power
supplies to more renewable sources such as the Tokelau Renewable Energy Project which has received funding
support from New Zealand’s Aid Programme.
Table 32
Case studies for integration of renewables on islands
Island renewables
King Island
The recently completed King Island Renewable Energy Integration Project (KIREIP)
aims to utilise renewable energy to meet 65% of the islands energy needs. The
KIREIP project integrates 390kW solar PV and 2450kW wind capacity into the 6MW
diesel engine plant. (Hydro Tasmania, 2014)
The high penetration renewables project focuses on the integration of enabling and
storage technologies, including a 3MW/1.6MWh (i.e. 45 minutes storage) Ecoult
UltraBattery (a lead acid battery / ultracapacitor hybrid), demand management and
smart grid technology and a diesel-UPS fly-wheel. (Hydro Tasmania, 2014)
In an earlier project, a vanadium redox battery was installed in 2003; however, it was
decommissioned after encountering technical issues (Hydro Tasmania, 2014).
Rottnest Island
A wind turbine-diesel hybrid system was installed on Rottnest Island in 2004 to reduce
the island’s reliance on diesel. The hybrid system comprised of a 600kW wind turbine
and two 320kW low load diesel generators, which were integrated into the existing
diesel system. The wind turbine produces around 35% of the Islands’ power needs
helps save approximately 430 000 litres of diesel per year (Rottnest Island Island
Authority, 2014).
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7.5.1
Outstations and homelands
In Australian sub-tropical areas and in arid inland regions, cattle are bred on large stations. The Northern Territory
produces over 600,000 cattle a year with a number of pastoral stations dispersed over half the Territory. The
pastoral industry is the Northern Territory’s third largest GDP earner, generating over $400 million directly into the
Northern Territory’s economy (Northern Territory Cattlemen's Association, 2009). Approximately 9,000 people live
in more than 500 small, remote and dispersed communities across the Northern Territory, known as homelands or
outstations. Similarly, a number of stations can be found across Queensland, South Australia and Western
Australia.
Cattle outstations usually have a small electricity load supplied by diesel generators. These are not serviced by
Power and Water Corporation or Indigenous Essential Services. They are delivered through a range of service
and electricity providers, with financial assistance through grants from Department of Housing, Local Government
and Regional Services (DHLGRS).
In 2010, the Northern Territory Cattlemen’s Association (NCTA) investigated opportunities for cattle stations to
convert to renewable power. Although the findings of the project highlighted a number of challenges to make
these projects cost effective, a few cattle stations have converted to renewable energy and provided positive
feedback on the NTCA website. The individual systems are typically very small but, aggregated, they can
represent an opportunity.
Some renewable energy projects that have been developed in the Northern Territory’s remote communities over
the last few years are listed in Table 33.
Table 33
NT remote communities renewable energy examples
Indigenous community renewable energy projects
Gulin Gulin (Bulman)
55kW system commissioned in November 2002
Gudabijin
4.6kW system upgrade commissioned in 2009
Lajamanu
290kW solar system (12 dishes) commissioned in 2006
Yuendumu
240kW solar system (10 dishes) commissioned in 2006
Ntaria
192kW solar system (8 dishes) commissioned in 2005
7.5.2
Aboriginal communities in Western Australia, not serviced by Horizon Power
A number of small, very remote communities and outstations in the Kimberly and very remote areas in the
Western Desert are not serviced by Horizon Power. The Remote Area Essential Services Program (RAESP)
created in 1997 is a program managed by the WA Department of Housing to support the supply of essential
services (including power) to some of these communities. In 2006, thirty-four regional providers were servicing
121 communities.
A key stakeholder is the Kimberley Regional Service Providers (KRSP), which provides a range of services
including maintenance, repair and capital works to communities in the Kimberley. As part of their Remote Area
Essential Service Program (RAESP) contract with the WA Department of Housing, they have been working for 54
remote communities to provide capital and maintenance works on their power and water systems.
Case study - the Shire of Ngaanyatjarraku
Based on the traditional lands of Ngaanyatjarra people, the Shire of Ngaanyatjarraku is home to approximately
1,840 people, in nine communities (see Table 34). The Shire covers over 150,000 square kilometres and is
arguably the most isolated in WA. Its largest community, Warburton, is over 1,500 kilometres from Perth (by road)
and 750 kilometres from Alice Springs (by air). The Shire provides all essential services (including diesel-fuelled
electricity supply) to its Indigenous communities.
Table 34
Communities in the Shire of Ngaanyatjarraku
Ngaanyatjarra communities
Estimated population
Warburton
720
Blackstone
202
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Ngaanyatjarra communities
Estimated population
Warakurna
194
Wanarn
161
Jameson
140
Tjukurla
94
Patjarr
59
Tjirrkarli
55
Kanpa
43
Source: (Shire of Ngaanyatjarraku, 2012)
7.6
Summary of key opportunity areas
With fast growing mining towns and over a thousand small remote communities and outstations across Australia,
the community segment represents a relatively untapped renewable energy market. Most communities supply
their electricity from expensive diesel fuelled power systems. Depending on remoteness and size of the
community, the diesel prices to communities vary from approximately $1.10/L to $1.70/L after rebates. This
corresponds to a fuel cost between $300/MWh and $450/MWh generation.
By contrast, the Levelised Cost of Electricity of solar PV in remote location such as the Pilbara can be expected to
be approximately $230/MWh3 for projects with a low penetration of renewable energy. This cost increases with
higher penetration of renewable energy into the system. However, ARENA’s RAR program should provide
financial support to enable renewable energy systems to remain competitive, even at higher penetration levels.
The key opportunities identified in the off-grid community market are:
-
islands that are not connected to mainland electricity supply.
-
growing mining towns, where renewable energy projects can be developed in collaboration with mining
companies and/or state owned service providers and other organisation such as the Pilbara Cities Office.
-
fringe-of-grid opportunities where there are large distribution loss factors, expensive augmentation which can
be addressed with embedded generation.
-
aggregation of small communities through the state owned service provider – Horizon Power, Ergon, Power
and Water Corporation, South Australian Government.
-
Aggregation of small Aboriginal communities or outstations through regional service providers or
independently.
In some cases, renewable energy also enables an increase in the reliability of the remote system. It can continue
to generate power when diesel supply has been lost (e.g. due to floods, insufficient diesel storage on site, or other
reasons). This is not an unusual situation in some very remote communities – a $1.3 million project was recently
completed to extend the fuel storage capacity at Maningrida (NT) to mitigate supply risks.
3
Based upon the Australian Energy Technology Assessment, BREE, 2012. This does not include costs associated with
integration into an off-grid system, which increase rapidly with medium to high solar penetration.
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7.7
Table 35
Challenges to renewable energy in the community market
Challenges and solutions to renewable energy in the community market
Challenges
Solutions
Small and dispersed – Apart from the major mining
towns, most Australian remote communities are small,
with populations sometimes less than 100 people and
rarely over a couple of thousand.
The higher cost of renewable energy projects in very
remote places must be balanced with the higher cost of
diesel in these same places.
These communities are also very dispersed and
remote, often located hundreds of kilometres from the
closest regional town.
The opportunities lie in aggregating a number of
renewable energy project opportunities together.
The remoteness increases the cost of renewable
energy projects. The small size of the renewable
energy opportunities also makes them less attractive
or unattractive to developers and investors.
Capacity constraints even in regional cities –
Although many regional towns are experiencing
energy load growth, much of the demand remains
relatively low. A range of financial incentives have
already caused an unprecedented number of
renewable energy installations within some regions. In
2011, Horizon Power enforced a maximum size
limitation on renewable energy systems in Exmouth,
Carnavon and Broome as a result of the fluctuations
and impacts of changing renewable output affecting
system stability.
Further research is required into the reliability impacts of
higher penetrations of renewables onto off-grid
interconnected systems, including control systems to
help network operators manage their systems more
effectively and the use of energy storage devices.
As highlighted previously stand-alone projects – even in
regional towns – are unlikely to attract major developer.
Aggregation of projects will likely be needed.
Generally many of the renewable energy opportunities
in off-grid towns will be below a few megawatts in
capacity due to the energy demand and system
capacity constraints outlined above. For developers in
this market the saturation point for renewables limits
their return on investment. Also the fixed cost of
establishing a remote renewable project is diluted by
the smaller installations and therefore dictates
developers to focus on large projects.
Land access rights - Sites where project
developments are proposed need to consider who
owns and occupies the land in order to gain land
access rights. Without these rights, fines can be
incurred.
Most councils or state departments will have a process
for seeking and obtaining land access rights. This will
need to be obtained prior to entering the site.
Community acceptance – Projects in remote areas
are likely to affect a community especially an
Aboriginal or Torres Strait Island community.
Community acceptance should not be overlooked as
strong opposition can cause major delays or even lead
to the project being abandoned.
Community consultation is an important step that needs
to start at the beginning of project development and
throughout the project life. Generally, experienced
stakeholder consultation consultants are required.
Written permission to enter Aboriginal land is required
by the Commonwealth.
For Aboriginal and Torres Strait Island community
consultation, this needs to be managed in a culturally
respectful way with the community and generally
requires an archaeologist and anthropologist with
experience working with Aboriginal or Torres Strait
Island communities.
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Challenges
Solutions
Aboriginal Cultural Heritage – Project sites may
contain Aboriginal cultural heritage sites, which are
generally protected sites. If destroyed, it can lead to
the Aboriginal community litigating the project owner.
This can cause major delays or even lead to the
project being abandoned.
This needs to be managed in a culturally respectful way
with the community and generally requires an
archaeologist and anthropologist with experience
working with Aboriginal or Torres Strait Island
communities. Depending on the state legislation, it may
require conducting a survey to identify sites of
significance, consultation, developing a management
plan and permission to implement the management
plan.
Capital cost – Renewable energy is capital cost
intensive. The state owned Network Service Providers
or Independent Power Providers who service the
remote communities are often capital constraint. The
large investment required is a key barrier to renewable
energy.
Costs will naturally reduce as technologies improve
(particularly in solar and energy storage technologies).
Competing subsidies – As per section 5.5.2, the
Community Service Obligation places obligations on
the state and territory governments to provide services
at a subsidised rate to remote communities. As such,
remote communities do not experience the actual cost
of supplying electricity to the remote regions. It plays a
critical role in ensuring adequate provision of an
uncompromised essential services such as electricity
to remote communities and industry. However, it also
means the financial benefit of remote renewable
energy projects will largely be gained by the state or
territory governments and the remote community endusers have limited financial incentives to deploy
renewable energy.
Recent consultations indicated that Power and Water
Corporation, Horizon Power, Ergon Energy and the
South Australian Government are all interested in cost
effective renewable energy options to offset diesel in
remote communities.
Reliability and economics – There is a significant
cost premium from associated with the remoteness of
these communities and their small size.
ARENA may provide some critical financial support. It
could also provide the industry an opportunity to
demonstrate that small reliable and robust systems can
be deployed in remote location.
Larger renewable energy systems enable small
economies of scale. However, the higher renewable
energy penetration imposes additional integration
costs (control systems and storage).
ARENA and the CEFC could have a critical role in
removing this barrier.
There is a potential role for new business models such
as renewable energy leasing from parties that have
access to capital.
ARENA could support community projects developed
through the state or territory owned Network Service
Providers.
Many State Governments intend to lower the CSO
contribution.
ARENA could also provide insights and learnings from
funded projects that might minimise future project risk.
Bringing skilled labour to solve any failure of the
system is disproportionately expensive in these small
remote communities. Any unplanned maintenance can
quickly offset all savings enabled by the renewable
energy system.
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Challenges
Solutions
Competition by CNG, LNG and grid extension –
Compressed Natural Gas (CNG), Liquefied Natural
Gas (LNG) or even grid extensions are in competition
with renewable energy options. Grid extension has
been considered an option for Mount Isa and the
South Australian remote communities close to the
NEM for example.
Although grid extensions may be in competition with
renewable energy hybrid projects it will enable
renewable resources that are largely untapped to be
developed as standalone large scale renewable energy
projects.
CNG and LNG may represent a tougher competition,
particularly, where the diesel engines are at the end of
their life and need to be replaced. Installing a gas
turbine will enable operational cost reduction while
having a lower capital cost than a diesel-renewable
hybrid system. However, gas prices are subject to
fluctuation and renewable energy can be seen as a
hedge against the risk of high gas.
ARENA’s RAR program could also enable renewable
energy to be in a better position to compete against a
gas alternative.
Labour costs – As highlighted above, there is a major
cost premium due to the remoteness. Skilled labour
costs are typically very high, particularly in mining
towns.
The increased labour costs in remote locations should
be taken into account. To prevent impacts of high labour
cost, the systems must be designed to be “robust and
reliable”, with remote monitoring and modulised
construction which will likely compress construction
schedules.
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8.0
Renewable Hybrid Considerations
8.1
Financial drivers
The development of the mining industry growth in Australia has brought significant new power generation growth
in remote regions of Australia. In some regions, such as the Pilbara, significant new power generation capacity is
needed to meet the demand of mines and the growing population of mining towns.
The principal benefit of off-grid renewable energy is to defray the risk of increasing fuel prices. There is currently
over 1.2GW of diesel generation capacity installed in remote Australia which supplies electricity to mines and
communities. These costs are expected to rise over time and are vulnerable to price shock events or supply chain
interruptions in international markets.
Mature renewable energy technologies (such as wind or solar PV) are already competitive with diesel in systems
featuring a low penetration of renewable energy. When including the Federal Government’s $0.38/L Fuel Tax
Credit, long term contracting and the buying power of a large mining company most large mine sites are likely to
be paying in the vicinity of $0.90 to $1.10/L for diesel fuel (or $26/GJ), while communities can pay up to $1.70/L
for diesel or more. This equates to $240 to $300/MWh for diesel cost only for larger mines and up to $450/MWh
for communities and smaller industrial loads (depending upon the efficiency of the diesel unit). By contrast, the
Levelised Cost of Electricity of a medium size solar PV plant in remote locations such as the Pilbara is
approximately $226/MWh4 (without grants or rebates). Therefore, for low penetrations of solar PV, there is a
genuine business case for utilising solar PV to offset diesel.
The main challenge to date is the fact that low-penetration renewable hybrid energy projects are generally too
small to make a significative difference to the fuel usage. As such, most mining companies and network service
operators have not found the savings worth the investment. As the penetration of renewable energy increases,
additional enabling technology must be used to ensure the stability of the electricity system. These include
communication and controls, storage, load management technology among others, which on average significantly
increase the cost of the hybrid project. In addition, the limited experience within Australia and generally smaller
project scales, typically dictate further cost premiums from the construction contractors and financiers. The RAR
program is intending to support the development of a number of off-grid projects that will demonstrate the
feasibility of off-grid systems and is expected to act as catalysts for future projects.
All sites will have different characteristics. In particular, the case for solar PV hybrid systems often depends
largely upon the delivered cost of diesel fuel at each site – the higher the cost of diesel, the more potential to save
money by integrating solar PV.
The viability of exploring renewables as a future fuel security and fuel price off-set opportunity has now become a
more attractive proposition in off-grid Australia. The modular nature of many renewable technologies (such as
wind and solar PV) and the cost reductions gained through recent expansion of these industries, means new
opportunities are emerging for developing off-grid clean electricity sources. It was identified through industry
consultations that some mining companies are currently investigating renewable energy options as a way to
reduce their energy costs, while reducing exposure to fuel price fluctuation risks and reducing carbon emissions.
Projects under consideration are focusing on offsetting diesel fuelled generation due to its higher relative costs
when compared to gas.
In the medium to longer term, a large increase in gas prices and price volatility is expected in Australia’s domestic
gas markets as local producers begin to service the demands of local Asian markets through export LNG. This will
likely further extend the viability of integrating renewables into gas fuelled systems, particularly as further
technology cost reductions are expected and energy storage devices evolve. It provides a comparison of the
costs of energy from diesel and solar PV assuming that all existing generation assets would remain on site to
provide adequate reliability. As such, it is a comparison between the short run marginal cost (SRMC) of diesel and
the full levelised cost of energy (LCOE) from solar PV including capital and operating costs. It shows that the cost
of solar PV has become competitive with the operating cost of diesel in recent years without rebates. Although
note that diesel costs and solar PV system costs vary substantially for each project.
4
Based upon the Australian Energy Technology Assessment, BREE, 2012. This does not include costs associated with
integration into an off-grid system, which increase rapidly with medium to high solar penetration.
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Figure 32
Solar PV cost comparison with diesel fuel-only costs (includes Fuel Tax Credit, excludes large consumer buying power;
assumes low penetration solar systems)
Source: AECOM 2013
Figure 33 below provides a comparison of the cost of solar PV with diesel generation as a function of PV capital
costs. For a given site, the delivered diesel price paid at the site is read on the y-axis and the expected renewable
energy project life is read on the x-axis. If the project site in one of the orange areas there is a business case for
the integration of renewable energy (the LCOE of renewable energy is lower than the SRMC of diesel). Whilst
projects in the grey zone are unlikely to cost effectively integrate renewable energy, however they may still seek
to invest in renewable integration to reduce the risk of fossil fuel price volatility and exposure to international price
volatility events. Overall, it shows that in some cases there is a business case for integrating renewable energy
into remote electricity systems where diesel costs are high and project lifetimes are suitably long.
Figure 33
Break-point analysis of the cost of solar PV with diesel generation, as a function of PV capital costs.
Source: AECOM
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Figure 33 also presents a series of three alternative capital cost assumptions for an associated renewable energy
infrastructure, represented in $/MW. Off-grid renewable capital costs are impacted by the site location, site
conditions, access to labour and construction materials and other specific opportunities and constraints.
8.2
Feasibility assessment guide
This chapter provides an overview of the technical and commercial considerations that should be addressed when
conceptualising, developing and delivering a remote renewable hybrid project. It must be noted that every project
is unique and developers should seek project-specific advice from independent or qualified professionals. For
simplicity, either solar PV or wind is assumed as the renewable electricity generation means as these are the
most common and commercially feasible technologies at the present time.
8.2.1
Existing system assessment
Before attempting to assess the feasibility of an off-grid renewable energy project and to define an appropriate
concept design, it is important to understand the capabilities and limitations of the existing remote electrical
system and the constraints associated with the site. All relevant information will be gathered and analysed with
particular attention given to the following:
-
Load - detailed information on the load across the electrical system will be critical. This includes load profile
and load steps and the impact of potential private solar systems. This may require additional power
monitoring to be installed in strategic locations within the distribution network.
-
Network configuration and parameters - The network configuration and key network parameters
(including voltage, frequency, fault currents etc.) must be well understood.
-
Existing diesel plant performance data - Including a detailed generation output, ideally with less than one
minute, time stamped generation data for the existing plant for at least 12 months.
-
Updated resource assessment data - Wind and solar resource assessments are an important part of the
technical feasibility study and will rely on the quality of the monitored data.
-
Financial information - Detailed operation and maintenance costs for the diesel power station and network,
information on electricity tariffs, equipment costs etc.
-
Site characteristics - including topology, geotechnical information, environmental features, surroundings
and shading elements (air services tower and vegetation), available land area and rooftops etc.
8.2.2
Optimisation
Once data has been reviewed, verified and summarised, an iterative optimisation process will generally be
required to define a suitable concept design.
During the pre-feasibility study, optimisation tools such as HOMER and ASIM can be used (refer to section 8.3
below). Some companies have also developed their own proprietary optimisation tools (such as ABB remote
optimisation model or AECOM’s CleanOpt tool).
During the detailed feasibility study, network modelling software such as DIgSILENT, PowerFactory or PSS
SINCAL are often used to analyse load flow and system stability. These software packages are not optimisation
tools - they are used to confirm the ability of pre-defined concept(s) to meet certain standards or requirements.
Having a complete and thorough understanding of the impacts that a project is going to have on the electricity
network is a key activity in the design of off-grid renewable energy systems. The electrical engineering and
analysis is usually time-consuming and can be a major hurdle to projects if not completed appropriately.
The feasibility study will typically lead to the definition of a detailed concept design and technical specifications
that will include:
-
Sizing of wind and/or solar systems
-
Wind and solar equipment specification and configuration
-
Sizing and specification of the storage system (if applicable)
-
Site location options and preliminary plant layout
-
Civil and structural concept design (earthworks, roads, access, foundation, mounting frames etc.)
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Electrical concept design including Single Line Diagram, cable reticulation, protection
-
Network connection concept design
-
Communication functional specification and concept schematic
-
Renewable resource assessment and generation potential assessment
-
Control and integration strategy, including diesel generation operation philosophy
-
Construction schedule and other construction and commissioning considerations
Technologies used in off-grid systems are rapidly evolving. It is important to remain in contact with suppliers and
use up-to-date technical and commercial information. Sub-assembly vendor categories to be considered include
energy storage devices, wind turbines, control systems, solar panels, inverters and transformers.
As part of the optimisation process, a number of “enablers” can be considered such as energy storage devices,
controllers, roll-out of smart meters or other demand management solutions designed to improve the concept
design (refer to section 8.4).
In addition, ARENA aims to provide tools for industry to streamline their business case development and provide
access to research and development groups to enable companies to stay up-to-date with the latest technology
development.
8.3
Table 36
Hybrid assessment tools
Commonly used hybrid assessment tools
Tool
Description
HOMER
HOMER is a software package initially developed by the US National Renewable Energy
Laboratory (NREL). HOMER is normally used during pre-feasibility studies to model both
the technical and financial factors in an off-grid renewable energy project.
The software is used to model different micro-grid concepts, which can include system
components chosen from HOMER’s database or defined by the user, these include:
-
-
Renewable energy components: Solar photovoltaic (PV), wind turbine, run-of-river
hydro power, biomass power fuel cell.
Thermal generation components: diesel generator, gasoline generator, biogas
generator, alternative and custom fuels generator, co-fired generator, electric utility
grid, microturbine
Storage: flywheels, battery bank, flow batteries, hydrogen
The load must be defined as a daily profile (hourly) with potential seasonal variations.
Deferrable load (such as water pumping or refrigeration), thermal loads and energy
efficiency measures can also be modelled.
During the simulation, HOMER performs energy balance calculations for each
configuration that has been pre-defined by the user. It compares the load (electric and
thermal) to the supply from each of the generation component (renewable and thermal)
and decides how the storage should be used (charge, discharge or neutral). The cost of
each option is assessed and options are ranked according to the financial merit.
ASIM
ASIM is an excel-based modelling tool developed by Power and Water Corporation with
funding support from ARENA. It simulates mini-grid renewable/diesel power system
operations on a one second basis to help analyse the technical and financial
performance of a hybrid system. The one second analysis helps detect system stability
issues (e.g. station blackouts) and other transient behaviour.
ASIM is composed of two components (excel spreadsheets and a C# power system
model). This enables the user to analyse and interpret the modelling results within the
spreadsheet. Since ASIM is open source, users will be able to modify the control
algorithms to simulate their particular system, which will improve the accuracy of the
results.
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Tool
Description
ASIM’s functionality enables optimisation of system sizing (including PV size and
spinning reserve requirements) and whole of life financial analysis PV/diesel hybrid
systems.
PVSyst
PVSyst is a solar simulation software developed at the University of Geneva
(Switzerland), and widely used by the solar PV industry.
The software is able to support the design and yield assessment of a grid connected or
an off-grid solar plant. Most parameters can be tailored to the project, which means that
the software can be used for preliminary or detailed analysis. The assessment involves
the choice of meteorological data, the definition of the system design, shading studies
and losses assessment.
The analysis is based on a detailed hourly simulation of an average year, although an
estimate of different probabilities of exceedance is possible (from P50 to P99).
The project financials can also be modelled within PVSyst. However, detailed financial
analysis is generally conducted in a separate model that uses PVSyst output yield
estimates as one of the key inputs.
Other assessment
tools
8.4
Other software packages exist that can be used for the assessment and design of off-grid
generation systems. These include solar modelling software packages such as PVDesign Pro, PV*Sol; general system simulators such as MATLAB or Simulink; network
simulation software such as PowerFactory and PSS/E; and wind software such as WAsP
or Windfarmer and others.
Enabling Technologies
As the penetration of renewable energy increases, additional enabling technologies must be used to ensure the
stability of the electricity system. These include communication and controls, energy storage, load management,
among others. These technologies on average will significantly increase the cost of the project; however they can
also enable a larger reduction in fuel use than would otherwise be possible. Additionally, due to their innovative
nature, use of these technologies will usually require some government support or other incentives such as
ARENA’s RAR program.
8.4.1
Energy storage
There are three broad energy storage configurations that could be considered prior to developing the concept
design. These configurations are generally described in Table 37 below:
Table 37
Overview of energy storage configurations with indicative performance factors
Energy Storage
Configuration
Description
Indicative max.
instantaneous renewable
penetration
Approximate reduction in
fuel consumption
Long-term storage
Energy storage for load
shifting
Greater than 50%
10% to 100%
Short-term storage
Short-term power delivery
for power quality
30% to 50%
5% to 15%
Less than 30%
0% to 10%
No storage
Source: AECOM
Note that the maximum instantaneous renewable penetration shown in Table 37 are subject to a number of
variables such as system size, reliability standards, spinning reserve, generation technology and more. Similarly,
the fuel reduction percentage is approximate and will depend on factors such as the load shape, renewable
resource and generation profile.
The choice of storage configuration significantly impacts the amount of variable renewable generation that can be
installed in the power system as well as the concept design and economics of the overall project. Energy storage
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is very expensive, so the benefits of economies of scale reduce as additional enabling technologies are required
to achieve higher penetrations.
The penetration level and operating philosophy of the energy storage also impacts the technology selection.
There are a number of different energy storage technologies, from batteries and capacitors to mechanical storage
such as fly wheels or pumped hydro. Figure 34 below provides a brief overview of the applicability of some energy
storage technologies.
Figure 34
Suitability of different energy storage technologies for grid-scale applications
Source: AECOM
8.4.2
Diesel generator performance
The technical characteristics of the diesel engine-generator (“genset”) affect the permissible penetration levels of
variable generation. Some of these characteristics are described in Table 38.
Table 38
Diesel genset characteristics
Genset Characteristic
Description
Low-load restrictions
At low loads, diesel gensets’ operating costs increase significantly through both reduced
fuel efficiency and increased maintenance costs. In addition, diesel genset
manufacturers typically provide limits on the minimum output of approximately 30 per
cent of the rated capacity, as well as the length of time it can operate at low loads.
Gensets with better low load performance are better suited to hybridisation projects as
they allow higher penetrations of variable generation.
Step load
A genset’s maximum step load capability affects the system’s ability to respond to
sudden large increases in load. This may be caused by a large reduction in the
renewable power plant’s output.
Ramp rate
Similar to step load, a genset’s maximum permissible ramp rate affects the system’s
ability to respond to large increases in load (over a longer period of time than steploads).
Most remote hybridisation projects will be seeking to integrate renewables into existing diesel fuelled generation,
where the performance characteristics of the plants are already set. However, parties considering hybrid plants
should investigate the performance of diesel gensets when purchasing new generation plant (i.e. for new loads
and replacement of existing gensets) to facilitate higher penetrations of renewables.
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8.4.3
Cloud tracking
Fully automated cloud monitoring systems under development, can be used in conjunction with the power
system’s controls to allow short term forecasting of solar PV generation. Once commercially proven these
systems will allow higher penetration of solar generation without requiring additional energy storage backup or
excessive “spinning reserve”.
In theory the control system will suitably adjust the intermittency level of the solar array depending on the forecast
cloud cover. Cloud Tracking Software commonly utilise cameras to observe the cloud patterns in the sky. Taking
into account other factors such as the sun trajectory and the location of the solar array, the software then
analyses the data to profile likely shading events caused by cloud cover.
While largely untested, Cloud Tracking Software is a promising method of providing relative cheap intelligence to
the control system to help enable higher penetrations of renewables and reduce the energy storage required to
cover the intermittency of solar generation.
8.4.4
Demand management
Demand Management is another cost effective way of reducing the energy storage reserves required to cover the
variability of solar generation. However, it is highly dependent on the availability of curtailable loads on the off-grid
network. Curtailable loads are power consuming processes which can be decreased (curtailed) at a moment's
notice by the hybrid controls system.
When determining the potential to implement demand management, it can be useful to categorise some of the
largest loads as critical or non-critical. Within the non-critical category, there will be significant variation. For
example, some loads may be curtailable for short periods only (minutes or seconds), while others may be
curtailable for longer periods (hours). It is also important to consider whether loads can be fully or only-partly
curtailed.
Some examples of curtailable loads include: chillers, heaters, water pumps and non-critical production processes.
8.4.5
Control systems
The hybrid control system will integrate the diesel genset operation with the renewable generation and other
enabling technologies (demand management, energy storage etc.) into a control philosophy that seeks to meet
the constraints of the Grid Code (i.e. power quality and reliability), while minimising operation costs.
Defining the overall control philosophy is a complex task that should consider the following:
-
Existing control system information
-
Load stepping and ramp-rate procedures
-
Existing operating reserves
-
Energy storage state of charge and operation limitations
-
Remote control functionality
-
Load shedding arrangements (i.e. automatic or manual and speed of)
-
Grid operation requirement
-
‘Grid code’ requirements
-
Power station and load monitoring structure
-
Other intelligence (e.g. operational patterns such as worker shifts, cloud tracking etc.)
8.5
Common hybrid risks
The following table highlights some of the key considerations and risks encountered in an off-grid hybrid system.
A developing risk analysis should be conducted at the beginning of the project and updated on a regular basis.
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Table 39
Common hybrid risks
Key risk area
Suggested mitigation approach
Renewable Integration
As the penetration of renewable energy increases, the
variability of generation can cause electrical stability
issues, if not configured correctly.
Also there remains a risk of operating the existing
diesel plant at low loads which can affect its efficiency
as well as the maintenance costs through commonly
seen issues such as bore glazing.
Battery Integration
Battery technology can store the excess renewable
energy and discharge it when needed to avoid
dispatching fuel fired generators. It can also help
maintain the stability of the electricity system. However,
integrating batteries can be costly and complex. Many
of the technologies on offer in the market lack proven
longevity and it can be difficult to obtain detailed up-todate technical or commercial information from
suppliers.
Faulty equipment delivered to site
Due to the remoteness of the off-grid sites, the delivery
of faulty equipment can result in significant delays and
cost overrun.
-
A number of technologies and operation
methodologies can be used including storage,
demand management, curtailment of the
renewable energy generation, maintaining
spinning reserve etc. The difficulty lies in defining
the optimal balance between all these solutions
-
A strong concept and detailed designs are
required to ensure that these risks are
engineered out.
-
In all cases, the reduced efficiency of the diesel
generator, impact of curtailment, storage
efficiency, impact of demand management etc.
must be accounted for during the feasibility study
and the final design.
-
Explore the use of alternative hybrid renewable
integration options either in addition or separate to
the battery energy storage system. This should
include a closer investigation of the demand
management options already considered and also
complementary hybrid enabling technologies such
as fly wheels, resistor banks or diesel UPS.
-
Early engagement with suppliers to review and
agree quality assurance procedures (i.e. Factory
Acceptance Tests) will help mitigate this risk.
Products and suppliers must be carefully selected
based on track record, technical capability and
commercial credibility.
-
Review and verification of supplier test reports
and certificates prior to leaving the factory.
Site constraints
The site may present a number of constraints including:
topology, shading from vegetation, planning and
approval restriction, distance to the connection point,
dusts, noise restriction, visual impact etc.
-
A site investigation is critical to identify the
constraints and take them into account during the
definition and the optimisation of the plant design.
Community acceptance
Community acceptance should not be overlooked as
strong opposition can cause major delay or even lead
to the project being abandoned.
-
Early and ongoing consultation is essential to
ensure that all stakeholders feel involved and
informed about the project
Resource dataset
Many remote sites do not have a reliable weather
dataset in close proximity to the proposed site that can
be historically or statistically referenced as a reliable
basis for future forecasting.
-
Understanding of financier’s requirements
regarding resource reliability will be essential to
ensure finance can be obtained.
-
Onsite solar and/ or wind measurement can
prove necessary, in which case the measurement
campaign should start early to avoid delaying the
project
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8.6
Project procurement – contracting strategy options
There are multiple options to consider when selecting the project procurement approach, each with their own
advantages, risks and coordination challenges. Some of the factors that will need to be considered by the project
host in selecting the project procurement strategy are:
-
Risk appetite, capability and resources available for the project on-site and the level of involvement in the
project management, construction, commissioning and transport logistics of each package
-
Quality control and management of defects during construction and beyond the defects liability period
-
Time schedule, particularly supporting studies such as environmental and renewable resource monitoring
which may impact on the scope of works
-
Interfaces between the various work packages and the risk of suppliers or contractors discharging
responsibilities
-
Desired level of involvement and control in the negotiation of supply contracts from the major components in
each work package (the ability to ensure that warranty, performance conditions and spares to adequately
cover the operation and maintenance of the facility in the future varies)
-
Costs of each of the elements of the project including equipment, labour, logistics and spares etc.
-
Existing IPP integration
The advantages and disadvantages of some of the most common procurement strategies are summarised in
Table 40.
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Table 40
Contracting strategy options
Option
Contract Structure
Engineer,
Procure,
Construction
Management
(EPCM)
Single EPCM Contractor
who tenders and
manages separate
supply contracts for
different work packages
(e.g. civil, electrical,
equipment procurement
etc.)
Engineer,
Procure,
Construct
(EPC)
Single fixed price EPC
contract for the full
project
Advantages
-
EPCM Contractor acts on behalf of the project owner or host
and takes responsibility for construction management and
supervision.
-
Limits the development and construction costs as the EPCM
would generally be engaged to do all upfront design studies
and contract/construction management.
-
Less up front specification work, which can enable projects
to be fast-tracked. Popular contracting structure in the
mining industry during the mining boom due to benefits of
early completion outweighing additional costs/risks.
Disadvantages
-
All performance, cost and schedule risks are
transferred to the project owner. The EPCM
Contractor helps to manage risk but generally
doesn’t take system performance risk. Generally
seen as higher risk than EPC and Multi-Contract.
-
Project owners will need to allow contingency for the
unknown procurement and construction risks.
-
Additional integration complexity due to multiple
contracts.
-
There may be limited scope for the project owner’s
staff to learn about the system during the
construction phase.
-
Greater control over specific equipment selected.
-
Greater flexibility than EPC i.e. contract packages can be
more easily modified to suit outcomes of environmental
studies.
-
Fixed price lump sum contract and hence costs are easier to
manage / forecast.
-
Single contractor responsible for system integration,
interfaces and the performance of all of its components.
-
Risk of performance, interface, delivery and costs are borne
by one single EPC Contractor therefore a lower risk for the
project owner.
May lack flexibility/control in respect to project
staging, sub-contractor selection, equipment
selection and technical design.
-
The predominant delivery structure applied to power projects
globally for the last 20 years.
More up-front design and specification work required
by the Project Owner.
-
Both contractor and project owner will need to allow
contingency for the unknown procurement and
construction risks.
-
Novation of warrantees and supply agreements can
be problematic – the owner may not negotiate
directly with suppliers.
-
-
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Option
Contract Structure
Multi-Contract
(EPC + Supply)
This is a typical hybrid
contract approach
whereby there is a main
EPC package and one or
more supply only
contracts.
E.g. the owner might
select an inverter and PV
technology and have
supply contracts with the
manufacturers. The EPC
would then construct
using these products.
Build Own
Operate (BOO)
+ Power
Purchase
Agreement
(PPA)
An Independent Power
Producer (IPP) will build,
own and operate the
power plant based on a
guaranteed purchaser of
the plant’s output
(through the terms and
conditions of a PPA).
Advantages
Disadvantages
-
Less risk than EPCM option for the project owner.
-
More than in EPC option.
-
Multiple fixed price lump contracts and likely cost saving
over EPC and EPCM strategy.
-
Undefined interfaces and project definition can
create delays and possible variations.
-
Ability to generate greater competition for subcontracts.
-
-
Provides greater opportunity for the project owner to be
actively involved in equipment selection and integration of
the project into the existing infrastructure.
Greater contracting, cost and construction
coordination and management required by project
owner. Greater number of supply contracts to be
negotiated and managed.
-
Greater flexibility than EPC i.e. contract packages can be
more easily modified to suit outcomes of environmental
studies (i.e. wind and bird monitoring).
-
Extent of supply only contracts will be limited by the
project owner’s resources and capability to integrate
the equipment.
-
Ability to efficiently utilise the project owner’s capability and
costs by integrating supply only contracts or work packages
that have limited interfaces
-
Increased flexibility over single EPC while still having an
EPC contractor ‘on the hook’ for the key project performance
risks.
-
Very little CAPEX for the project owner (paid for by the IPP)
-
Reduced control of operation of plant
-
Single contract (i.e. PPA)
-
-
Single party responsible for system integration, interfaces
and the long term performance of all of its components.
Difficult to integrate new power generation projects
with existing PPAs due to take-or-pay arrangements
(or similar)
-
Risk of performance, interface, delivery and costs are borne
by IPP.
-
Can be difficult to include load curtailment and
energy storage operating procedures in the PPA
-
This option is common delivery model used by remote mine
sites for their power supply and management.
-
Project owner has reduced control on operating
practices of power plant, which can restrict future
improvements to operating procedures
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9.0
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Appendix A
Renewable Resources
and Technology Status
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Appendix A
Renewable Resources and Technology Status
Australia current draws upon a variety of energy generation resources as part of its energy mix and has sort to
adopt a variety of renewable energy technology to take advantage of its various renewable resources.
The relative costs and maturity of different technologies are constantly evolving in response to the policy
environment, learning effects as technologies mature, economies of scale, commodity prices driven by local and
global demand and changes to the price of input costs. For example, supportive government policy, in
combination with rapid expansion in the global production of PV modules and substantial decreases in the price of
polysilicon, has contributed to dramatic reductions in the price of PV units and hence the LCOE over the past two
or three years. This has contributed to the 150 per cent increase in installed solar PV capacity in Australia
between 2010 and 2011.
These factors are expected to continue to make renewable energy technologies more cost competitive with fossil
fuel-fired technologies over the next four decades. As a result, the Australian generation mix will evolve to reflect
these developments. BREE projects that by 2049–50 the share of renewable energy sources in the electricity
generation mix will increase dramatically to 51 per cent, from 10 per cent in 2010–11 under Treasury’s carbon
price projections.
The Australian Bureau of Resources and Energy Economics developed an Australian Energy Technology
Assessment in 2012 which the most up-to-date cost estimates for 40 electricity generation technologies under
Australian conditions. The costs were normalised into a levelised cost of electricity (LCOE) benchmark that allows
for cross-technology comparisons over time. The figure below assumes technology learning and development
maturity by 2020 and focuses primarily on grid connected generation means however it does provide a plausible
indication of renewable technology options and their relative competitiveness if adapted to a remote application.
Figure 35
Projected LCOE for Power Generation Technologies in Australia by 2020 (NSW), with carbon price set to zero.
LCOE FOR 2020 TECHNOLOGIES (NSW*)
* Note: Default region is NSW except bown coal
technologies (VIC) and SWIS scale (as specified)
450
400
350
LCOE ($/MWh)
300
LCOE includes, where relevant, allowance for:
- Carbon Price
- CO2 transport and sequestration cost
- Plant capital cost (EPC basis) within battery limits
- Owners costs excluding interest during construction
- Fixed and variable operating costs
- Fuel costs
- Economic escalation factors
250
200
150
100
50
0
Source: (BREE, Australian Energy Technology Assessment, 2013)
The below table provides a summary of the research conducted with focus made on technologies suitable to a
greater than 10kW remote renewable application. Renewables in the off-grid renewable energy market will in the
short term be dominated largely by retrofitting wind and solar at low levels of penetration with existing off-grid
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power stations. As the confidence in this emerging market develops and new technologies become available it is
expected that other technologies will become the primary energy source in remote locations.
Table 41
Off-grid Renewables Technology & Resource Potential Overview
Current Off-grid Market
Potential5
Off-grid Clean
Energy Options
Typical
Plant
Size
Technology
Availability
Australian
Deployment
Potential
On-shore Wind
<3MW
Commercial
High
Off-shore Wind
<7MW
Commercial
Limited
Forecasted annual
av. growth 2008-35 &
Share of Energy
Production6
10.1 per cent
Growth
Off-grid
Communities
Off-grid
Mining &
Industrial



Micro Wind
<100kW
Commercial
Moderate
Energy Storage
<10MW
Commercial
High
N/A



Hybrid Integration
Technologies
Various
Various
High
N/A


Rooftop Solar PV
<20kW
Commercial
High


Commercial
High


-





1 per cent Share


Utility Solar PV
Concentrated Solar
Thermal
14 per cent Share
4.1 per cent Growth
1 per cent Share
<300MW
Commercial
Moderate
Large Hydro
<20GW
Commercial
Limited
0.2 per cent Growth
Small Hydro
<2MW
Commercial
Limited
4 per cent Share
Geothermal
<300MW
(Pre)
Commercial
Moderate
N/A Growth
4 per cent Share
2.1 per cent Growth
Bioenergy
<150MW Commercial
Limited

Wave
<200MW
PreCommercial
Moderate
N/A


Tidal / Current
<250MW
PreCommercial
Moderate
N/A


High
Forecasted as 25 per cent of Energy Production
by 2035
Renewables
5
There is very large renewable resource in Australia however, the size of the market (for the coming years to 2020) is largely
driven by the Renewable Energy Target.
6
Forecasts obtained from BREE’s Australian Energy Projections to 2034-35, Dec 2011. Note these projections do not focus on
the off-grid renewable market more the macro Australian energy mix.
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Hybrid Power Systems and Enabling Technologies
Hybrid Power Systems and Enabling Integration Technologies
Technical Description
While Australia has an abundance of renewable resources, many of the technologies adopted provide an
intermittent supply output and must be integrated with a continuous supply of continuous generation.
Hybrid power systems combine different technologies to form an integrated power delivery system to a load or
network. They can include the combination of a form of renewable energy with another renewable, a fossil fuel
technology or a form of energy storage or a combination of all of these.
Energy Storage can be integrated in a variety of ways to help manage the intermittency experienced by many
renewable resources. It can include flywheels (kinetic energy), pumped hydro storage, and thermal or battery
technologies. Depending on the particular hybrid or stand-alone renewable application will determine the duration of
storage required. Short term storage is conventionally used to manage power quality while long term storage often
requiring greater amounts of energy to be stored.
In remote applications Smart Grids technologies can be adapted in a range of ways. With the growing availability of
IT infrastructure in remote locations remote micro-grids can obtain greater visibility and control of the load, monitor
and manage network performance and generation input. It can be adapted into metering technology to better
understand remote load characteristics, reduced operating costs by deploying pre-paid meters through to embracing
advanced telemetry and control technologies to manage system flexibility.
Integrated Control and Energy Management Systems can enable greater functionality particularly in report
applications by being able to balance supply and demand as a result of system balance requirements and
renewable energy input. Many invertor technology suppliers are adapting sophisticated control and protection
functionality with their products to enable hybridised installation to operate effectively without additional hardware.
Australian existing off-grid power stations and enabling technology market
Enabling technologies are an
essential technology in remote
application to assist the smooth
integration of a variety of renewable
energy sources.
Figure 36
Off-grid Gas and Diesel Power Generation
Hybrid or stand-alone remote
renewable systems will benefit from
further application to remove
perceptions of being a complicated
and unreliable technology option.
Together they have the potential to
improve efficiency in consumption
of fossil fuel and increase the input
from renewable energy fuel
sources.
Source: AECOM
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Hybrid Power Systems and Enabling Integration Technologies
Economics
Australia has a few case studies of renewable/fossil hybrids however they remain relatively uncommon though with
the uptake of off-grid renewables in Australia driven by increasing operating fuel costs of existing off-grid plant in
addition to Government subsidies such as ARENA’s RAR Program will together provide incentive to the market to
integrate renewables.
Main feasibility drivers
There are some clear feasibility drivers of adopting enabling technologies into hybrid systems or stand-alone off-grid
renewable plant, include:
-
A dispatchable generation means is critical for many off-grid power grids to maintain supply as an independent
system and enabling technologies are essential in many cases to integrate renewables.
-
The benefits of the renewable input can be maximised through optimised integration of enabling technologies.
-
By optimising the overall system efficiency can help the business case for renewables.
Is there a business case for off-grid hybrid systems or enabling?
Enabling technologies are an essential supporting element in any off-grid renewable system, particularly hybrid
systems.
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On-Shore Wind Generation
Wind Generation
Technical Description
Utility scale on-shore wind generation represents the most mature form of renewable energy generation (excluding
hydro). On-shore utility scale wind farms typically contain units in the 1 MW to 3 MW range with hub heights of 70 to
100 metres and rotor diameters of 70 to 120 metres. Utility-scale wind farm usually have a lower cost per kW
compared to small and medium scale wind turbines.
Small to medium scale wind turbines (from a few watts to a few hundred kilowatts) can be ground mounted or roof
mounted. There are a number of existing technologies on the market with horizontal or vertical axis. These
technologies are still relatively expensive and far less mature than utility scale wind turbines.
Australian wind resource
The best regions for wind energy in
Australia are generally along the
south-western, southern and southeastern coast and extending inland
as shown in the Renewable Energy
Atlas below.
Figure 37
Wind Resource of Australia
Source: Windlab Systems, SA Government
State of the Australian wind market
The installed capacity of wind farms in Australia has increased rapidly since the introduction of the original 2001
Mandatory Renewable Energy Target. South Australia has the largest installed capacity of wind generation plants in
Australia, with 15 operating wind farms and total installed capacity of 1,203 MW, accounting for 48 per cent of
Australia’s total installed wind capacity (RenewablesSA, 2011). Despite the significant deployment of off-shore wind
farms globally in recent years, there is no known plan for off-shore wind energy generation in Australia.
Currently, utility-scale on-shore wind energy is currently the least expensive form of renewable energy generation in
Australia and is therefore expected to provide the largest contribution to the Renewable Energy Target. Although a
number of developers have already secured the sites with the greatest wind potential, there remains significant
untapped wind resource and hence high market potential for wind energy in Australia.
The capacity of wind required for the electricity retailers to meet their Large-Scale Renewable Energy Target (LRET)
obligations through to 2020 will depend on the capacity factor of the individual wind farms. Based on an average 32
per cent capacity factor and assuming that wind contributes 75 per cent of each retailer’s LRET obligation, it is
assumed that the overall market size for wind generation in Australia is 11GW.
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Wind Generation
Small and medium wind farms have been used to supply power to small communities such as the 600kW Rottnest
Island, WA wind turbine to supplement existing diesel-generated power.
Economics
The deployment of wind power in Australia is largely driven by the LRET. With increasing competitiveness and a
strong Australian dollar, the installed cost of utility scale wind farms is currently in the order of AU$1.5 - 2.5
million/MW. The Levelised Cost of Energy (LCoE) of wind energy has also reduced considerably in recent years
due to improvements in turbine efficiency and reliability. Typical recent LCoE figures for wind farms in Australia are
believed to be in the order of AU$80-100/MWh. The Clean Energy Council state the price of wind-generated
electricity is approximately AU$90-120/MWh (CEC, 2011).
The capital cost of off-shore wind energy is approximately double that of on-shore wind energy in the current
market.
Main feasibility drivers
In addition to the typical project development considerations of the wind farm, the following should be considered;
Site specific wind resource
The feasibility of a wind farm development depends heavily on the local wind resource, which is very site specific.
The wind resource in the remote areas needs to be assessed on a project by project basis. It is clear that several
large commercial wind farm projects have been constructed and are under development throughout the country at
facilities that are generally close to the coast and aligned with the extent of the SWIS or NEM or within areas where
the wind resource is well known such as Broken Hill, NSW.
Elsewhere knowledge about Australia’s wind resource is reasonably poor. Mapped results need to be treated with
great caution, given the accuracy of the modelling employed and the lack of correlation with any detailed wind
resource monitoring. Detailed information is often held closely by those who have invested in obtaining it. Financiers
typically require at least one year of onsite wind resource monitoring with a wind mast at a height that corresponds
with hub heights of potential wind turbines prior to investing into a project.
Development and Regulatory Approval
Obtaining a Development Approval for a wind farm is typically seen as more challenging than for a solar plant. Wind
projects are subject to a number of regulations and standards which can vary between jurisdictions. The
Development Approval process will include a number of studies, and will define strict regulations around noise
assessment, ecological impact and visual amenity. It is not rare for a wind project to encounter strong community
opposition, particularly if the community has not been adequately consulted in the project development process.
Community consultation is an important activity for successfully developing a wind farm.
The Victorian Government recently approved Amendment VC78 to the Victoria Planning Provisions (VIC
Government (a), 2011) which recently imposed more stringent planning considerations for wind farm developments
in Victoria, including the requirement to provide a plan showing all dwellings are within two kilometres of proposed
turbine locations.
Transport
Logistics of transporting large turbines and specialised equipment such as large cranes for installations to remote
locations needs to be considered carefully during the feasibility study, including road access.
Site Constructability
Wind farms are often in remote locations and access to construction materials needs careful consideration in
addition to an understanding of the geotechnical characteristics.
Grid Connection
Typically wind projects connecting into remote networks need careful consideration due to their intermittency and
impact on a weak network’s stability.
Time of production
One of the obstacles for wind energy development is the variability of the resource. In the National Electricity Market
(NEM), there is currently sufficient spinning reserve for wind variability to not be a significant challenge. However,
the time of production has a significant impact on the revenues. The production from the South Australian and
Western Australian wind farms are generally greater at night, during off-peak demand times.
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Wind Generation
Is there a business case for off-grid wind systems?
There is a business case based on a Levelised Cost of Electricity (LCoE) basis for utility scale wind farms to
compete with electricity generated using diesel. In theory, off-grid applications could therefore offset their diesel by
deploying wind energy.
However, the wind resource being very site specific, it is difficult to draw a general conclusion. Wind energy is
certainly an option to consider for off-grid communities but it needs to be assessed on a project by project basis. In
particular, small scale wind will likely have a higher LCoE than utility scale in addition to the costs involved in control
and integration any system. Also, many of the remote opportunities for renewable integration in northern Australia
are susceptible to monsoonal or cyclonic conditions which will affect construction and design rating of wind projects
in these regions.
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Solar Photovoltaic (PV)
Solar PV Generation
Technical Description
Solar PV technologies convert sunlight into electricity using semiconductor materials that produce electric currents
when exposed to light. Solar PV can be installed on roofs or ground mounted in large fields. Solar PV panels can be
fixed or in a tracking arrangement (single axis or dual axis).
Australian Solar PV resource
Australia has the highest solar
radiation per square metre of any
continent (IEA 2003) globally.
Australia receives an average of 58
million PJ of solar radiation per year
(BoM 2009), almost 10,000 times
larger than the Australian total
energy consumption.
Figure 38
Theoretically, if only 0.1 per cent of
the incoming radiation could be
converted into usable energy at an
efficiency of 10 per cent, all of
Australia’s energy needs could be
supplied by solar energy. Although
the regions with the highest solar
radiation are deserts in the
northwest and centre of the
continent, as shown in Figure 38,
there are significant solar energy
resources in areas with access to
the electricity grid. The solar energy
resource (annual solar radiation) in
areas of flat topography within 25
km of existing transmission lines
(excluding National Parks), is
nearly 500 times greater than the
annual energy consumption of
Australia.
Average Daily Solar Exposure (Annually)
Source: (BOM, 2012)
State of the Australian Solar PV market
Small scale solar PV systems have been widely installed in Australia leading to the development of a strong local
solar PV industry. The number of Clean Energy Council accredited installers and designers in Australia has grown
from around 237 in early 2006 to nearly 4,273 by late 2011, nearly an eighteen fold increase (CEC, 2011). The
original deployment was largely driven by former generous state government feed-in-tariffs and other subsidies such
as the solar multipliers. Although the number of new installations has declined in the last year, small scale solar PV
(under 100kW) continues to be driven by the Small-Scale Renewable Energy Scheme (SRES).
Large-scale solar PV is establishing itself with Australia’s largest solar PV installation developed by Frist Solar at
Greenough River Solar Farm in Western Australia (10 MW plant) and a number of larger systems are currently in
development. Development in large-scale solar was initially driven by the Federal Government’s investment into the
Solar Flagships program and the Large-Scale Renewable Energy Target (LRET). ARENA and the CEFC are
expected to provide further support in the future deployment of large scale solar.
Concentrated solar PV systems that focus sunlight onto PV modules is in its infancy in the Australian market. Aside
from demonstration projects, there is a 235 kW concentrated solar PV installation at Alice Springs Airport.
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Solar PV Generation
Economics
In recent years, solar PV module cost reductions supplemented by a strong Australian dollar resulted in significant
solar capital cost reductions. Commercial scale PV systems are currently expected to have an installed capital cost
between AU$2 million/MW and AU$3 million/MW. Bloomberg New Energy Finance released a report with a median
Q1 2012 solar PV LCOE of approximately $170/MWh (FrankfurtSchool, 2012). Lower prices have been seen
internationally however relatively high prices in the Australian market are expected to remain in the near future,
driven by wage levels as well as limited large-scale experience.
Many mines and communities in remote locations source electricity from diesel generation, and often pay over
$300/MWh in fuel and carbon only (i.e. excluding CAPEX). These costs are expected to rise over time and are
vulnerable to price shock events or supply chain interruptions in international markets.
Solar PV and other renewables can be integrated with existing diesel units to provide a highly reliable power supply.
Such renewables now provide a cheaper source of electricity while maintaining the mining industry’s stringent
reliability requirements; some renewables are now cheaper than diesel power — supplying electricity at competitive
rates.
Main feasibility drivers
In addition to the typical project development considerations of the Solar PV plant, the following should be
considered:
Existing electricity supply
Positive business cases are largely dependent on the existing electricity supply available. Remote off-grid
communities that rely on existing diesel generation have a stronger business case for implementation of solar PV as
it can offset the high operating cost of diesel generation.
To date, solar PV is unlikely to be competitive with off-grid gas generation without government funding or subsidies.
Location Consideration
Sites that require minimal work to optimise the capacity factor of a system will minimise construction costs. In order
to minimise earthwork costs, a ground mounted solar PV system will require a large amount of relatively flat land
with a typically preferred land gradient below 5 per cent and north facing. Fixed tilt systems typically exceed 2
hectares per MW of solar plant. Consideration of trees, buildings or surrounding hills that may cause shading and
hence reduce electricity production is also essential. Most off-grid systems are located in areas with available flat
land and typically of low value. Consequently, the large footprint of solar PV systems is unlikely to present a
significant challenge.
Locating of solar PV plants in remote locations can mean they are susceptible to theft or vandalism. Also access to
construction resources, serviceability in isolated locations and project size for the development cost investment
return should also be considered.
Is there a business case for off-grid Solar PV systems?
For a current delivered diesel price estimated at around AU$1/L for typical mining projects or approximately
AU$1.30/L for remote communities including the Fuel Tax Credit, integrating solar PV into off-grid systems
operating on diesel is now a cost effective option. Low levels of solar PV integrated into most systems require only
minimal integration costs, provided some or all the existing generation assets would remain installed to support
reliability. If a higher integration cost can be justified, the infrastructure to support a higher solar PV penetration
level can be included (such as batteries and short term flywheel storage).
In addition to the financial benefits, sourcing energy from solar PV insulates against rising diesel fuel costs and the
potential fuel price volatility in international markets. It also reduces exposure to the carbon price and minimises the
issues related to uncertainty in the forward price of carbon.
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Solar Thermal
Solar Thermal
Technical Description
Concentrated solar thermal power (CSP) involves using lenses or mirrors to focus a large area of sunlight onto a
single point which creates intense light and heat that is used to generate electricity.
Various techniques and configurations are used for CSP plants globally. These include parabolic troughs or Linear
Fresnel with a linear absorber tube running through a focal point, or mirrors that concentrate solar energy to the top
of a tower.
Australian Solar Thermal Resource
Solar thermal resource is
determined by the amount of direct
normal solar irradiance (DNI) as
CSP relies upon DNI to focus onto
a collector to generate heat and
electricity. Provided below is a map
of the annual average DNI at a
resolution of 10,000km2 grid cells.
It shows there is a high solar
thermal resource in the central
regions of all states except Victoria
and Tasmania. In particular, there
is a very high solar thermal
resource on the coastal regions of
Western Australia.
Figure 39
A 2008 study by Wyld Group and
MMA found locations with high
potential for solar thermal systems
based on high DNI, proximity to
local loads and high electricity costs
from alternative sources. These
locations included the Port Augusta
region in SA, north-west VIC,
central and north-west NSW,
Kalbarri near Geraldton in WA, and
Alice Springs to Tennant Creek in
NT (GeoscienceAustralia, 2010).
Direct Normal Solar Irradiance
Source: (GeoscienceAustralia, 2010)
State of the Australian solar thermal market
Currently there are only a few working solar thermal power plants in Australia. The largest standalone CSP power
station in Australia is the Liddell Power station, which is a demonstration plant of approximately 1.5 MW. A 44 MW
solar thermal boost project is being constructed at Kogan Creek, Queensland to support an existing coal power
station. The Kogan Creek project received considerable upfront subsidies from the State and Federal Government.
The industry experience and technology is still quite new in Australia. Unlike solar PV, which is very modular and
has been able to establish itself in the domestic market, CSP is much more feasible in the form of large-scale
projects or as integrated directly into the organic Rankine cycle of existing thermal plants.
The Australian Government through the Australian Renewable Energy Agency’s (ARENA) Emerging Renewables
Program is funding a feasibility study into hybridising solar thermal with gas at Collinsville Power Station. The $5.6
million study will assess the viability of converting a decommissioned 180MW coal power plant into a 30MW hybrid
solar thermal/gas power station by maximising use of existing infrastructure. If feasible, it aims to encourage further
coal power plant conversions.
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Solar Thermal
Economics
Solar thermal technologies currently have a higher overall cost of energy compared to solar PV. Solar Thermal
energy costs are currently estimated to be in the order of AU$200-300/MWh with a typical capital expenditure of
AU$5 million/MW (Entura, Hydro Tasmania, 2010).
Main feasibility drivers
In addition to the typical project development considerations of the Solar Thermal plant, the following should be
considered;
Scale
The business case for solar thermal strengthens for large scale applications (typically 50MW and above) and
therefore requires large areas and significant load to be supplied.
Large flat area
For some solar thermal technologies including parabolic troughs and linear Fresnel lenses, a flat site with a gradient
below 5 per cent is preferred. In contrast, a flat area is not necessary for solar power towers or parabolic dishes. A
large area is also required with an estimated 2 hectares of land required per MW of electricity generated
(GeoscienceAustralia, 2010).
Most off-grid systems are located in areas with available flat land and typically of low value. Consequently, the large
footprint of solar thermal systems is unlikely to present a significant challenge.
Wind loading
Aside from high DNI, it is important to consider the wind loads at a site as a CSP plant comprises of large
structures. Low wind areas are preferred as this will reduce the additional amount of reinforcement required and
thus construction costs.
Access to water
CSP plants require access to small/medium volumes of water for cleaning mirrors and maintaining the designed
reflectivity. Larger volumes of water will also be required for the mechanical water based cooling systems typically
associated with a CSP plant. However, this can be avoided with an alternative dry based cooling system.
Solar Glare/ Reflectivity
There are various organisations such as airports and nearby communities that are concerned about solar glare from
CSP plants. Generally the project must prove there is no detrimental impact to overhead flight paths or nearby
communities.
Opportunity for integrated storage
Whilst thermal energy storage is expensive, a CSP plant with energy storage can decrease the cost per kWh
produced as it can dispatch electricity during demanded periods when it is of most value.
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Tidal
Tidal
Technical Description
Harnessing the energy potential of the oceans tides falls into two main technology categories:
-
Tidal barrages which are essentially a dam or dyke type structure which encloses a bay, tidal lagoon, inlet or
estuary. A power station containing low head turbines, similar to those used in conventional hydropower
facilities are installed in the barrage and generate electricity by exploiting the potential energy of the rising and
falling tides.
-
Tidal stream or current generators are free standing turbines which are founded on the sea bead in tidal or
ocean current channels. These turbines are similar to wind turbines in that they harness the kinetic energy of
the fluid flow (in this case the tidal currents). Tidal stream generators employ very similar technology to wind
turbines however they benefit from the much higher energy density of tidal currents; meaning that a much
smaller rotor can be used to produce the same energy output.
Both these technologies are still comparatively underdeveloped and remain a high cost to integrate meaning there is
only limited project examples around the world.
Australian Tidal & Ocean Current Resource
The north west of Australia
experiences a tidal range of up to
10 m, one of the largest in the
world. It is this region from Port
headland north to Darwin that has
the greatest potential for tidal
electricity generation with both
barrage and tidal stream generators
possible. The region is also dotted
with inlets and other large tidal
water bodies which may be ideal for
tidal generation.
Figure 40
Tidal energy potential in Australia
There are also four main ocean and
non-tidal coastal currents
surrounding Australia which have a
potential to generate in the order of
44TWh/year (CSIRO, 2012).
Source: (ABARE & Geoscience Australia, 2010)
State of the Australian tidal & ocean current market
The world’s most productive wave energy is more available in countries with unsheltered coastlines, facing oceans
where wind is converted to wave energy over fetch distances of hundreds to thousands of kilometres. This includes
the Americas, Australia, Ireland, Portugal, parts of Scandinavia, South Africa and the United Kingdom.
The potential for power generation from the oceans tides and currents is undoubtedly large, however tidal energy
potential is comparatively low compared with wave energy. Currently commercial scale tidal generation facilities
operational globally, are primarily tidal barrages. There are currently no tidal generation facilities in operation in
Australia although tidal generation in Australia has been investigated since the 1960’s and 1970’s.
The Doctors Creek site near Derby in Western Australia was investigated in the 1990’s for a 48MW tidal barrage
development. The project proposed to construct two barrages across the two arms of Doctors Creek, one retaining
the high tides and the other the low tides. With the water elevation difference created between the two arms it was
possible to generate 48MW of continuous tidal power. The project was abandoned due environmental concerns and
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Tidal
cost blowouts and in 2004 a diesel power plant was built to meet the local electricity needs. The Doctors Creek site
has since been resurrected is once again under consideration with a revised layout capable of generating 100 MW.
Other sites in Western Australia such as the Ord River (Tidal Energy Australia), Walcott Inlet, Secure Bay, St
George Basin and Rothsay Water (Baker, 1991) have also been considered but not investigated in sufficient detail
to determine the feasibility of these sites.
Economics
The cost of developing a tidal power project in Australia is still largely unknown as no such facilities have been
developed yet. It is likely to be highly variable and dependent on site conditions, particularly the tidal range,
topography and bathometry, geology and proximity to existing transmission infrastructure.
The production costs of tidal energy technologies are estimated by the IEA to be from US$60 /kWh to US$300/kWh
(2005). Tidal barrage schemes are at the lower end of this scale and tidal stream generators at the upper end of this
scale (ABARE & Geoscience Australia, 2010).
Main feasibility drivers
In addition to the typical project development considerations of the tidal plant, the following should be considered:
Predictability
The main benefit of tidal energy is that unlike other forms of renewable energy, tidal energy is very easily
predictable. When paired with storage (i.e. pumped storage hydro) the predictable nature and immunity to climatic
conditions of tidal generation means that it can provide reliable base load electricity supply.
Barrage type schemes may also serve a secondary purpose in some locations such as enabling rail or road
transportation across a bay or inlet.
Resource far from the electricity users
The dislocation of the tidal energy resources from potential energy users presents a significant challenge for future
tidal generation in Australia due to the high cost of transmission.
Environmental impact
High potential environmental impacts are also a key barrier to development in Australia particularly for tidal barrage
schemes. (Australian Institute of Energy)
Is there a business case for off-grid tidal systems?
The tidal and ocean current potential is limited to relatively small areas along the Australian shore, which
significantly limits the potential for off-grid tidal systems. In addition, there are significant economies of scale in
developing larger tidal systems, which means that the technology wouldn’t be suitable to supply small off-grid loads.
The high predictability of tidal electricity generation could however be attractive in some remote application,
including to the mining industry along the North West coast of Australia. However, the cost of the technology is still
high compared to other renewable energy sources such as wind and solar PV.
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Bioenergy
Bioenergy
Technical Description
Bioenergy uses biomass (organic material) to produce electricity, heat or liquid fuels for transport.
In Australia, biomass is primarily utilised in two forms:
-
Direct combustion of biomass to heat water into steam for a steam turbine to generate electricity
-
Use of landfill gas in the gas turbine to generate electricity
Globally, biomass has been converted into electricity using methods including anaerobic digestion, pyrolysis and
gasification.
Australian Bioenergy Resource
The potential bioenergy resources
in Australia are large and diverse
with unused biomass residues and
waste streams a significant underexploited resource.
Figure 41
Land use and bioenergy facilities in Australia
The Clean Energy Council has
estimated the long term electricity
generation potential to 2050 of
these biomass resources below. It
suggests bioenergy can contribute
around 73TWh of electricity to
Australia by 2050. By comparison,
the 20 per cent Renewable Energy
Target by 2020 is 41TWh.
Source: (GeoscienceAustralia, 2010)
State of the Australian bioenergy market
Currently, Australia is generating bioenergy from waste by-products to ensure there is a sustainable supply that
does not compete with native forests, edible crops and fertile lands. Biomass sources used in Australia for
generating heat and electricity include bagasse, wood waste, landfill gas, sewage gas, black liquor, food and
agricultural wet waste.
In 2011, electricity generation from bioenergy (including biomass and biogas) amounted to 773MW, which is around
1 per cent of total electricity generation in Australia. Over 60 per cent of this was from bagasse combustion with
landfill gas the second largest contributor (CEC, 2011).
Accounting for the Renewable Energy Target (RET) and other government policies, ABARE predicts bioenergy will
have an average annual growth rate of 2.2 per cent, largely from bioenergy generation projects in Queensland.
It is possible that biogas could supplement natural gas within a few decades; however energy crops are likely to be
a competing with food crops for suitable agricultural land. Both terrestrial freshwater algae and marine algal
seaweeds are a promising alternative feedstock for biogas generation and these would not be competing for land
resources. Biogas could be carbon neutral and may fit well with an energy mix of biofuels and renewable energy
sources.
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Bioenergy
Programs and policies supporting biomass electricity
Through the RET, Large-Scale Generation Certificates (LGCs) are applicable to the following biomass types; wood
waste, agricultural waste, energy crops, bagasse, black liquor or landfill gas, waste from processing of agricultural
products, food waste, food processing waste, biomass-based components of municipal solid waste, sewage gas
and biomass-based components of sewage. LGCs are created by renewable energy power stations directly in the
online REC Registry.
The Victorian Government provides a feed-in-tariff of a minimum 8 c/kWh for excess electricity exported to the grid
for biomass systems less than 100kW (VICGovernment (b), 2013).
The Australian Capital Territory (ACT) Government has introduced the ACT Waste Management Strategy 20112025, which sets out goals to achieve full resource recovery and a carbon neutral waste sector. From this strategy,
the ACT Environment and Sustainable Development Directorate are currently seeking expressions of interest for
waste processing systems that recover resources from urban forest materials and residual waste streams into
higher value applications till May 2013.
Table 42
Long term generation potential of animal waste
Resource
Long term potential (GWh)
Agricultural-related wastes
50,566 GWh
Sugarcane
7,800 GWh
Wood-related wastes
5,060 GWh
Urban biomass (including urban
timber wastes)
4,320 GWh
Landfill gas
3,420 GWh
Sewage gas
929 GWh
Energy crops
534 GWh
Total
72,629 GWh
Source: (CEC (d), 2008)
These figures are in line with the estimate from Clean Energy Council (presented in Table 42), which provided a
detailed electricity generation potential by segment and for a wide variety of biomass sources by 2020 and by 2050.
The three most promising segments for future bioenergy projects are agricultural and sugar cane waste, forest
residues and urban waste.
Agricultural and residual waste
Over the past few years, new opportunities for anaerobic digestion have been identified in the food processing and
farming industries and studies have been undertaken on meat processing sludge and animal manure. Berrybank
piggery has been producing 3.5MWh per day since 1991 from its 0.225 MW power plant fuelled by pig manure. The
Clean Energy Council (2008) estimated the long term potential from this industry of about 200GWh per year.
Feedlot cattle and poultry farms are estimated to have a long-term potential of 440GWh per year and 840GWh per
year respectively. Abattoirs or slaughterhouse represent a potential for development from the utilisation of solid
wastes. If by 2020, 30 abattoirs implement anaerobic cogeneration plants, 340GWh per year can be generated, with
a long-term estimate of about 1770GWh per year.
Urban waste
Utilisation of urban solid organic wastes, such as timber, paper, food and garden waste is steadily growing and has
significant potential for energy generation. In 2002-03, approximately 9.5 Mt of organic urban waste was sent to
landfill annually. The potential electricity generation for 9 Mt of urban waste is 103GWh, with a long term estimate of
around 4300GWh (Clean Energy Council 2008).
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Bioenergy
Forest residues
Australia has extensive areas of forest and dry agricultural land that could potentially be accessible for biomass crop
production as illustrated in Figure 41. There is a potential to utilise wood waste and forest residues for electricity
generation. Some industry stakeholders have recently proposed to use wood wastes and other bio-energy
resources for co-firing conventional thermal power stations and suggested that the Carbon Tax could be sufficient to
incentivise the growth of this market.
The use of residual forest waste is controlled by some regulatory mechanisms, including Regional Forest
Agreements to prevent potential of environmental damages on the Australian forests’ ecosystem. The regulations
limit the utilisation of waste residues from forests as a source for renewable energy.
Economics
The cost of a biomass facility varies depending on the size, site, transportation, labour involved, energy capturing
and conversion technology and waste material. It is likely that bioenergy power stations greater than 1MW are
cheaper with estimated capital costs for a 40MW plant at around AU$2.5 million per MW of installed capacity, in
contrast to more than AU$8 million per MW for a plant size less than 1MW (CEC (a), 2011).
The positive business case increases for bioenergy production models that generate electricity from cheap or
‘negative-cost’ residues or waste at the biomass source site such as at landfill and sewage sites, paper, saw or
sugar mills.
Main feasibility drivers
In addition to the typical project development considerations of the biomass plant, the following should be
considered:
Availability of biomass
A biomass system requires a significant amount of organic material. The feasibility of the system is dependent upon
the availability of this organic material at the volumes required for the desired plant capacity. It also depends on the
composition and quality of the organic material as the more contaminants within a waste stream the more complex
the processing system.
Some types of biomass can be used to produce other commodities such as food given valuable fertile lands. There
are also competing alternative uses for forestry and agricultural wastes such as composting and feed for animals. It
is important the choice of biomass is carefully considered to avoid any potential negative environmental and social
impacts.
There is a large source of biomass however its availability also depends on many parties within the supply chain
and how potential biomass is currently handled. Current forestry, agricultural and waste processes are generally
seasonal may likely need to change in order to effectively divert potential biomass.
Transportation
The location of the bioenergy power plants requires a balance between biomass supply transportation costs and the
electricity load. For biomass with low calorific value, it is preferable for the plant to be as close to the biomass
source in order to minimise transport costs of large volumes of biomass.
Approvals
Planning approvals can be difficult to obtain for certain forms of biomass systems due to stringent health and safety
requirements.
Is there a business case for off-grid bioenergy systems?
The rainfall generally is relatively low in Australia but areas where rainfall exceeds 300mm per annum may show
potential for mallee cropping and straw.
In the Pilbara and other mining regions, the management of waste generated from remote mining communities and
mining sites is becoming a focus as they develop comprehensive waste recycling and disposal plans. The business
case for off-grid landfill gas and waste to energy plants for electricity generation may be possible in some regions.
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Hydro
Hydro
Technical Description
Hydropower produces approximately 16 per cent of the world’s electricity and over four-fifths of the world’s
renewable electricity (IRENA 2012).
Hydropower systems use the energy in flowing water to produce electricity or mechanical energy. There are two
basic configurations to harness the moving water to produce energy: firstly dams with reservoirs and secondly “runof- river systems” that do not require large storage reservoirs and are often used for small-scale hydro projects.
Hydro systems can be very large and able to produce thousands of megawatts such as the Hoover Dam of 2,074
MW (USA), the 22,500MW Three Gorges Dam (China) and the 10,000MW Guri dam (Venezuela).
However, small run of river hydro, which can be a few megawatts down to less than 100kW, has been around a very
long time, and is now experiencing an increase in popularly globally. It has an important role to play in the future
sustainable development of our planet.
Australian Hydro Resource
Hydropower is a mature energy
generation technology that has
been employed in Australia for
more than 100 years. Currently
hydropower contributes on average
around 14,000 GWh of electricity
annually in Australia, which
represents more than two thirds of
the total renewable electricity
generation. Australia has 108
operating hydroelectric schemes
with a combined generating
capacity of 8,186 MW
(Ecogeneration, 2011). Sixteen of
these schemes have a capacity of
over 100 MW and just 3 with a
capacity greater than 500 MW or
more, all of which are located in the
Snowy Mountains Scheme, the
largest being Tumut 3 which has a
capacity of 1,500 MW (Geoscience
, 2012).
Figure 42
Australian operating hydroelectric facilities ( > 10 MW)
Despite the large size of the
Australian land mass, the
hydropower potential is
comparatively small compared to
other countries. This is due to
Australia’s low and variable rainfall,
high rates of evaporation, and
limited areas of suitable
topography.
Source: (GeoscienceAustralia, 2010)
State of the Australian hydro market
It is not anticipated that we will see new large scale hydropower development in Australia in the next decade due to
the scarcity of suitable sites. Future growth in Australia’s hydropower generation capacity is expected come from:
-
rehabilitation and upgrade of existing hydropower plants
-
retrofitting of hydropower plants to existing water storage dams, irrigation canals and water pipelines.
-
development of new small scale run-of-river hydropower plants
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Hydro
With the exception of the AGL’s 140 MW Bogong Power Station Bogong Power Station in Victoria, commissioned in
2009, new hydropower developments in recent years have been small and mini hydropower developments. These
schemes offer the a number of advantages over large scale hydro including lower environmental impact, lesser
demand on valuable water resources, ability utilise on existing water resources infrastructure, and much shorter
development timeframes.
Opportunities for small scale hydropower development are known to exist on many streams in Victoria, New South
Wales and Queensland and also in the retrofitting of water dams.
Over 80 per cent of the hydropower capacity in Australia is located in Tasmania and New South Wales. The Snowy
Mountains Hydroelectric Scheme in NSW, which has a capacity of 3,800 MW, accounts for around half of Australia’s
total hydroelectricity generation capacity. There are also hydroelectricity schemes in north-east Victoria,
Queensland, Western Australia, and a single mini-hydroelectricity project in South Australia (Geoscience , 2012)
Economics
The cost of developing a hydropower project is highly variable and dependant on the site conditions, particularly
topography, geology, hydrology and proximity to existing transmission infrastructure. The capital cost of developing
a hydropower project is typically between AU$1.5million/MW and AU$6million/MW (International Energy Agency,
2010) and operating costs are estimated at AU$0.03-0.04/kWh. In some instances the development cost can be
lower where it is possible to utilise existing infrastructure, such as retrofitting a hydro plant to an existing water
storage dam. The following Australian examples demonstrate the inherent variability in hydropower development
cost:
-
Jounama hydropower plant (14.4 MW) – Snowy Hydro (2010) AU$16.5million, AU$1.15million/MW (Snowy
Hydro , 2010)
-
6 Mini-Hydropower Plants (7 MW) – Melbourne Water (2010), AU$25million, AU$3.6million/MW
(Ecogeneration, 2011)
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Bogong Power Station (140 MW) – AGL (2009) AU$234million, AU$1.7million/MW (Australian Energy
Resource Assessment, 2010)
-
Wivenhoe Dam Mini Hydro (4.5 MW) – Stanwell (2003) AU$7.6million, AU$1.7million/MW
-
“The Drop’ Mini Hydro (2 MW) – Pacific Hydro (2002) AU$6.5million, AU$3.3million/MW
-
Pindari Dam Mini Hydro (6 MW) – Stanwell (2001) AU$9.2million, AU$1.5million/MW
-
Ord River Hydro Scheme (30 MW) – Pacific Hydro (1997) AU$76million, AU$2.5million/MW (Clean Energy
Council)
The Levelised Cost of Electricity is similarly variable.
Main feasibility drivers
Australia has a limited number of large rivers and hence there are limited sites available for large-scale deployment
of hydropower. It is commonly agreed that Australia has already developed most of its hydro potential.
Is there a business case for off-grid hydro systems?
Scarcity of Australia’s water resources and potential environmental impacts are the key constraints to development
of new hydropower assets in Australia.
While retrofit mini hydropower projects have previously been approved in Australia, there is very little precedent for
new small scale green-field hydropower development. It is generally viewed that obtaining a Development Approval
for these projects is considerably more challenging than for other renewable technologies due to the unavoidable
impact on a watercourse.
Recent droughts and increasing variability in Australia’s rainfall further contribute towards an uncertain future for
hydropower in Australia.
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Wave
Wave
Technical Description
Globally, wave power generation is in its infancy with most technologies still in the research and development phase
or early phases of the demonstration and commercialisation learning curve.
There are a very large number of wave technologies, all based on the principle on the exploitation of the wind-driven
wave energy. There are three general categories: Oscillating Water Column systems (with a pneumatic chamber
and air turbine), Oscillating Body systems (with various rotation bodies) and Overtopping Devices (based on the use
of reservoirs).
Australian Wave Resource
The wave resource is typically a
combination of waves generated by
wind blowing across the ocean
surface, and ocean swell created
by the interaction of weather
pressure systems moving across
the ocean surface in conjunction
with wind. The wave and swell
components have differing
wavelengths and amplitudes and
wave energy converter
technologies are typically optimised
to capture one or other of these
components.
Figure 43
Spatial distribution of time-averaged wave power on the Australian continental
shelf (kW/m)
There have been a number of
studies to quantify the Australian
wave resource; however there is a
lack of primary measured data and
hence significant uncertainties in
the estimations of the magnitude
and characteristics of the wave
resource.
Source: (GeoscienceAustralia, 2010)
State of the Australian wave market
In Australia there are companies actively developing wave power technologies, and Table 43 lists the wave power
pilot and demonstration projects installed and operating in Australian waters.
Table 43
Wave power pilot and demonstration projects in Australia
Project
Company
State
Start up
Capacity
Fremantle Wave Energy
Research Facility
Carnegie Wave Power Ltd
WA
2005
0.10 MW
Port Kembla (wave energy)
Oceanlinx
NSW
2006
0.50 MW
Lorne Pier Demonstration
unit
AquaGen Technologies
VIC
2010
0.0015MW
Source: (GeoscienceAustralia, 2010), (AquaGen, n.d.)
Australia has an exceptional wave energy resource with one study estimating that approximately half of Australia’s
electricity demands could be met if 10 per cent of the wave energy resource along the south-western margin of
Australia were used to generate electricity study (Hemer & Griffin, 2010). Interestingly, the study also noted that
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there are temporal-spatial variations in the incidence of the wave energy: specifically that when the southern coast
incident wave power peaks, the western coast teds to be calm and vice versa. This finding implies that if the
Western Australian grid electricity networks were interconnected with the NEM, a distributed deployment of wave
energy generation across the south-western margin would collectively be able to provide a reasonably consistent
supply of electricity (in aggregate the generation profile would have similar characteristics to a base load generator).
In the short to medium term, the growth of the wave energy sector is anticipated to be relatively slow in Australia
whilst wave technologies undergo research and development and progress through the demonstration and
commercialisation learning curve. Current proposed demonstration projects for Australia are shown in Table 44.
Table 44
Proposed demonstration wave projects
Project Description
Company
State
Start up
Capacity
Perth Wave Energy
Carnegie Wave Energy Ltd
WA
2014
5 MW
Port Fairy project – gridconnected bioWAVE
BioPower Systems
VIC
2013
0.25MW
Commercial scale
greenWAVE device
Oceanlinx
SA
2013
-
Portland
Ocean Power Technologies
VIC
-
19MW
Source: (SustainabilityVIC, 2013)
The wave resource along the south-western margin of Australia is among the best in the world. The total wave
energy on the entire Australian continental shelf at any one time, on average, is estimated to be about 3.47 PJ. In
general, wave energy appears to be closer to major population centres and the electricity grid than tidal or ocean
thermal energy.
Most of the current generation of wave energy converters are designed to operate in water depths up to
approximately 50m. The spatial distribution of time-averaged wave power on the Australian continental shelf (kW/m)
in water depths of 50m or less is illustrated in Figure 43 where the colour scaled wave power at each location
represents a time-average of an 11 year time series from March 1997 to February 2008, and the state figures are
the mean of the available power.
There are significant differences in the wave regime between the south-western margin and eastern coast of
Australia as illustrated in Figure 43. The optimal deployment of most wave energy converter technologies requires
sites with consistent unimodal sea states. The wave regime along the South-Western Australian margin is
particularly attractive for wave generation projects.
Economics
Wave power technologies are in their early stage of commercialisation. The Levelised Cost of Electricity is likely to
be similar to global predictions for the first quarter of 2012 at around $450/MWh (FrankfurtSchool, 2012).
The Australian Energy Resource Assessment refers to the International Energy Agency production costs between
US$60 – 300 per kW (in 2005 dollars), with wave systems at the higher end of the cost spectrum.
Until the technology develops, the cost of wave power will likely be higher than other more mature renewable
energy technologies.
Main feasibility drivers
In addition to the typical project development considerations of the wave plant, the following should be considered;
Resource
The wave resource and the proximity of a load are key aspect of the feasibility of a wave project.
Geotechnical environment
For the wave technology involving anchoring to the ground, the geotechnical of the marine ground is absolutely
critical. The wave technology system will purposely been implemented in areas with strong wave power, and there
have been cases of system that have been pulled off the ground and landed on the cliff.
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The submarine topography is also a key factor in the selection of the transmission cable route and the choice of
construction techniques.
Environmental Impact
The wave power system as well as the grid connection will have an impact on the submarine environment and
studies including ecological impact assessment, submarine noise assessment and environmental impact
assessment will likely be required.
Is there a business case for off-grid wave systems?
More primary measured data is required to quantify Australia’s wave resources. The Victorian government has
aimed to address this challenge having deployed two buoys to monitor the waves at Port Campbell and Cape
Bridgewater.
There is no commercially mature wave technology at this point in time, resulting in most government funds being
directed at research and demonstration projects. For example, the Perth Wave Energy project received ARENA
funding for the world’s first demonstration of a complete grid-connected, commercial scale Cylindrical Energy
Transformation Oscillator (CETO) system.
Due to the immaturity of the technology, the capital cost of the system including grid connection is still relatively high
compared to other renewable energy sources. In 2010, the IEA suggested that wave power costs were between
$6.8milion/MW and $9milion/MW (IEA, 2010).
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Geothermal
Geothermal
Technical Description
Geothermal energy uses the natural heat from deep ground wells to produce electricity via a turbine and heat.
Geothermal energy is a major resource and potential source of low emissions renewable energy suitable for baseload electricity generation and direct-use applications.
This heat is either held within dry rocks or transferred into water which is held underground in aquifers, or through
direct heat associated with surface volcanic activity. As Australia is not an active volcanic country the primary
geothermal resources are sedimentary aquifers and hot dry rocks.
Based on the IEA, the global geothermal capacity is approximately 9GW, with an electricity generation potential less
than 1 per cent of the global electricity demand.
Australian Geothermal resource
Australia has substantial potential for Hot
Rock/ Engineered Geothermal Systems
and Hot Sedimentary Aquifer resources.
These are respectively associated with
buried high heat-producing granites and
lower temperature geothermal resources
associated with naturally-circulating
waters in aquifers deep in sedimentary
basins.
Figure 44
Potential for Geothermal in Australia
Australia’s geothermal potential has
recently been estimated to be circa
2,572,280PJ (Sub-economic Identified
Resources) and a recent reports
estimates that geothermal electricity
generation could account for up to 40 per
cent of the Renewable. However, there is
a knowledge gap around geothermal
potential as only sporadic drilling tests at
a limited number of locations in Australia
have been executed.
There are known large geothermal
resources in remote locations providing
opportunities to connect to nearby large
loads such as mines or processing
facilities.
Source: Hot Rock Energy Program, Australian National University
State of the Australian Geothermal market
For geothermal electricity generation, Australia is at proof-of-concept or early commercial demonstration stage. The
only commercial operating geothermal plant in Australia is the 80kW Birdsville Organic Rankine Cycle Geothermal
Power Station. As such, significant Australian Federal Government funding has been directed to these early stages
of development.
In 2009 government funding were awarded to four commercial-scale renewable energy projects as part of
Renewable Energy Demonstration Program (REDP). The successful geothermal projects included a 30MW project
developed by MNGI, which received a $63 million grant and the 25MW Cooper demonstration project developed by
Geodynamics, which received a $90 million grant).
In addition, $50 million funding was devoted to the Geothermal Drilling Program (GDP) to provide assistance to
companies seeking to develop geothermal energy with the cost of proof-of-concept projects including drilling
geothermal wells. Seven projects have received funding, capped at $7million per project: (Australian Government
(c), 2009)
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Geothermal
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MNGI Pty Ltd - at Paralana, South Australia
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Panax Geothermal Ltd – at the Limestone Coast, South Australia
-
Hot Rock Ltd – Koroit in the Otway Basin, Victoria
-
Geodynamics – near Bulga in the Hunter Valley, New South Wales
-
GRE Geothermal WA1 Pty Ltd – Perth metro area, Western Australia
-
Greenearth Energy Ltd – near Geelong, Victoria
-
Torrens Energy Ltd – Parachilna, South Australia
Since this allocation of funding, the geothermal companies have not raised enough capital to complete their
projects, which had a negative impact on investor confidence for the geothermal market.
State governments have also contributed funding to various projects. The Victorian Government’s Sustainable
Energy Large Scale Demonstration Program awarded $25 million to the Geelong Geothermal Power Project for
proof of concept and a 12MWe demonstration plant (VIC Government (c), 2013). The Western Australia
Government’s Drilling Incentives Scheme provided a total of $295,000 to Green Rock Energy Limited for drilling
(AGEA, 2011).
In the private sector, Origin Energy joint venture with Geodynamics Limited invested significant fund in geothermal
energy, including in the development of a concept for the Enhanced Geothermal System (EGS) project in the
Cooper Basin, South Australia in March 2009. However, Origin Energy, has recently withdrawn further funding to
the project closing the joint venture (Parkinson, 2013)
Currently, the only available funding for geothermal projects is the Australian Government’s Australian Renewable
Energy Agency (ARENA) $126 million Emerging Renewables Program.
As geothermal project development relies upon large upfront capital investment, the geothermal market is likely to
remain slow and small until additional private and government funding becomes available.
Economics
Until geothermal electricity generation projects are commercially viable the cost of geothermal electricity will remain
uncertain. A major barrier is the upfront cost of establishing a geothermal plant. Around 70-80 per cent of the overall
cost of geothermal electricity can be attributed to exploration, well-drilling and plant construction. In particular,
drilling can comprise a third to half of the total cost of a geothermal project with cost estimated around $10-15
million to drill to a well depth of 5km (GeoscienceAustralia, 2010).
Main feasibility drivers
In addition to the typical project development considerations of the geothermal plant, the following should be
considered;
Exploration and proof of concept
Exploration and proof of concept is costly and there is a large risk in proving a geothermal resource is suitable and
reliable for a certain electricity production yield. Some initiatives have aimed to improve transparency across the
industry such as the creation of the Australian Code for Reporting Exploration Results, Geothermal Resources and
Geothermal Reserves. In addition, the NSW and VIC government encourage information sharing, providing public
access to interactive state maps and state resource assessments.
Location of the resource
For remote locations where there are known large geothermal resources, the challenge is finding a load to match
the potential geothermal electricity generation or fund the additional transmission infrastructure to connect to the
electricity grid.
Environment and Planning
Environment and planning issues are involved both at the exploration stage and development stage. The Victorian
Government has been supportive of geothermal explorations, issuing over 20 exploration permits across the state.
Recent explorations indicate hot sedimentary aquifers between Geelong and beyond the border of South Australia
(VIC Government (c), 2013).
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Geothermal
Is there a business case for off-grid geothermal systems?
Depending on the geothermal resource however some remote areas of Queensland, Western Australia, Northern
Territory and South Australia may be good prospects for future geothermal power generation. Due to the maturity of
many of the projects and limited understanding of the geothermal resource in Australia, geothermal developments
will likely begin in locations that are situated close to either the SWIS or NEM due to the additional costs associated
with remote applications of the technology.
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